DELEK LOGISTICS PARTNERS, LP
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the Fiscal Year Ended December 31, 2013
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to
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Commission file number 001-35721
DELEK LOGISTICS PARTNERS, LP
(Exact name of registrant as specified in its charter)
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Delaware
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45-5379027
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(State or other jurisdiction of
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(I.R.S. Employer
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incorporation or organization)
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Identification No.)
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7102 Commerce Way
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Brentwood, Tennessee
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37027
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(Address of principal executive offices)
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(Zip Code)
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(615) 771-6701
(Registrant’s telephone number, including area code
)
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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Common Units Representing Limited Partner Interests
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
o
No
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Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
o
No
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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
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No
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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 (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
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No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (section 232.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments of this Form 10-K.
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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. (Check one):
Large accelerated filer
o
Accelerated filer
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Non-accelerated filer
o
Smaller reporting company
o
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
o
No
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The aggregate market value of the registrant's common limited partner units held by non-affiliates as of June 28, 2013 was approximately
$302,530,188
, based upon the closing price of its common units on the New York Stock Exchange on that date.
At
February 21, 2014
, there were
12,152,498
common limited partner units,
11,999,258
subordinated limited partner units and
492,893
general partner units outstanding.
Documents incorporated by reference: None
TABLE OF CONTENTS
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Unless otherwise indicated or the context requires otherwise, the terms "Delek Logistics Partners, LP," the "Partnership," “we,” “us,” or “our” may refer to Delek Logistics Partners, LP, one or more of its consolidated subsidiaries or all of them taken as a whole.
Statements in this Annual Report on Form 10-K, other than purely historical information, including statements regarding our plans, strategies, objectives, beliefs, expectations and intentions are forward looking statements. These forward looking statements generally are identified by the words “may,” “will,” “should,” “could,” “would,” “predicts,” “intends,” “believes,” “expects,” “plans,” “scheduled,” “goal,” “anticipates,” “estimates” and similar expressions. Forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties, including those discussed below and in Item 1A, Risk Factors, which may cause actual results to differ materially from the forward-looking statements. See also “Forward-Looking Statements” included in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations included in Item 1, Business, of this Annual Report on Form 10-K.
ITEM 1.
BUSINESS
General
Delek Logistics Partners, LP (the "Partnership") is a Delaware limited partnership formed in April 2012 by Delek US Holdings, Inc. ("Delek") and its indirect subsidiary, Delek Logistics GP, LLC, our general partner. Unless otherwise indicated or the context requires, "Delek" and "Sponsor" refer collectively to Delek and any of its subsidiaries, other than the Partnership, its subsidiaries and its general partner. In November
2012
, the Partnership completed its initial public offering (the "Offering").
The Partnership's business primarily consists of the assets, liabilities and results of operations of certain crude oil and refined product pipelines and transportation, storage, wholesale marketing and terminalling assets which were previously owned, operated or held by Delek and certain of its present subsidiaries, including Delek Marketing & Supply, LLC ("Delek Marketing") and Lion Oil Company ("Lion Oil") and former subsidiaries, including Paline Pipeline Company, LLC ("Paline"), which is now a subsidiary of the Partnership. During 2013, we also acquired certain assets from unrelated third parties. For accounting purposes, prior to the completion of the Offering, the assets, liabilities, and results of operations of the aforementioned assets owned by these related parties related to Delek Logistics Partners, LP Predecessor (the "DKL Predecessor"). Delek is our primary or sole customer for a substantial majority of our assets.
Overview
The Partnership primarily owns and operates crude oil and intermediate and refined products logistics and marketing assets. We generate revenue and contribution margin, which we define as net sales less cost of goods sold and operating expenses, by charging fees for gathering, transporting and storing crude oil, for storing intermediate products and feed stocks and for marketing, distributing, transporting and storing refined products. A substantial majority of our existing assets are both integral to and dependent upon the success of Delek's refining operations as our assets are contracted exclusively to Delek in support of its refineries in Tyler, Texas (the "Tyler Refinery") and El Dorado, Arkansas (the "El Dorado Refinery"). Accordingly, a substantial majority of our contribution margin is dependent upon Delek's successful operation of these refineries and the commercial agreements we have entered into with Delek with respect to these refineries. See "—Commercial Agreements" for a description of each agreement. In addition to the services we provide to Delek, we also provide crude oil transportation services for, and terminalling and marketing services to, third parties in Texas, Tennessee and Arkansas. Some of these services are provided pursuant to contractual agreements with such third parties. See "—Commercial Agreements—Other Agreements with Third Parties."
We are not a taxable entity for federal income tax purposes or the income taxes of those states that follow the federal income tax treatment of partnerships. Instead, for purposes of these income taxes, each partner of the Partnership is required to take into account his, her or its share of items of income, gain, loss and deduction in computing his, her or its federal and state income tax liabilities, regardless of whether cash distributions are made to such partner by the Partnership. The taxable
3
income reportable to each partner takes into account differences between the tax basis and fair market value of our assets, the acquisition price of such partner's units and the taxable income allocation requirements under our partnership agreement.
Recent Developments
El Dorado Terminal and Tankage Acquisition
On February 10, 2014, the Partnership, through our subsidiary Delek Logistics Operating, LLC ("OpCo"), completed a transaction with Lion Oil, pursuant to which OpCo acquired a refined products terminal, storage tanks and ancillary assets on and adjacent to Lion Oil's El Dorado, Arkansas refinery (the "El Dorado Refinery") from Lion Oil (the "El Dorado Transaction"). The purchase price paid for the assets acquired was $95.9 million in cash financed with borrowings under the Partnership's amended and restated senior secured revolving credit facility. In addition, the parties entered into several contracts and amended certain existing contracts in connection with the El Dorado Transaction. The assets acquired in the El Dorado Transaction consist of:
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The refined products terminal located at the El Dorado Refinery (the "El Dorado Terminal") which consists of a truck loading rack with three loading bays supplied by pipeline from storage tanks located at the El Dorado Refinery, along with certain ancillary assets. Total throughput capacity for the El Dorado Terminal is approximately 26,700 barrels per day ("bpd"). For the year ended December 31, 2012, approximately 12,649 bpd of refined products were throughput at the El Dorado Terminal.
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One hundred fifty-eight (158) storage tanks and certain ancillary assets (such as pumps and piping) located adjacent to and at the El Dorado Refinery with an aggregate shell capacity of approximately 2.5 million barrels (such storage tanks and certain ancillary assets, the "El Dorado Storage Tanks"). The El Dorado Storage Tanks, together with the El Dorado Terminal, are sometimes hereinafter referred to as the "El Dorado Terminal and Tank Assets."
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In connection with the El Dorado Transaction, the Partnership entered into and amended, as applicable, the following definitive agreements:
El Dorado Throughput and Tankage Agreement
. On February 10, 2014, in connection with the El Dorado Transaction, Lion Oil and OpCo, and, for limited purposes, J. Aron & Company ("J. Aron"), entered into the El Dorado Throughput and Tankage Agreement. Under the El Dorado Throughput and Tankage Agreement, OpCo will provide Lion Oil with throughput and storage services in return for throughput and storage fees. The initial term of the El Dorado Throughput and Tankage Agreement is eight years and Lion Oil, at its sole option, may extend the term for two renewal terms of four years each. Effective February 10, 2014, Lion Oil assigned J. Aron its rights to use and transport materials through the El Dorado Terminal and Tank Assets until the expiration of Lion Oil’s amended and restated supply and offtake agreement with J. Aron. Despite the assignment Lion Oil still retains certain rights and obligations under the Throughput and Tankage Agreement. For a further discussion of J. Aron’s involvement in this agreement, see "—El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement."
Second Omnibus Amendment
. The Partnership entered into an Omnibus Agreement with Delek, our general partner, OpCo, Delek, Lion Oil, and certain of the Partnership’s and Delek’s other subsidiaries upon the completion of the Offering on November 7, 2012. In this Annual Report on Form 10-K, we refer to this Omnibus Agreement as the “Omnibus Agreement.” On July 26, 2013, in connection with the acquisition from Delek of the refined products terminal and 96 storage tanks and ancillary assets adjacent to the Tyler Refinery from Delek, the Partnership entered into an amendment and restatement of the Omnibus Agreement (the “First Omnibus Amendment”).
On February 10, 2014, in connection with the El Dorado Transaction, the Partnership entered into a second amended and restated Omnibus Agreement (the "Second Omnibus Amendment"). The Second Omnibus Amendment included the following, among other things: (i) certain modifications in the reimbursement amounts to be paid by Delek and certain of its subsidiaries under the Omnibus Agreement for certain operating expenses and capital expenditures incurred by the Partnership or its subsidiaries; (ii) certain modifications of the indemnification provisions under the Omnibus Agreement in favor of the Partnership with respect to certain environmental matters; and (iii) the increase of the annual administrative fee payable by the Partnership to Delek under the Omnibus Agreement for corporate general and administrative services from $3.0 million to $3.3 million, which is prorated and payable monthly.
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El Dorado Lease and Access Agreement
. On February 10, 2014, in connection with the El Dorado Transaction, Lion Oil and OpCo entered into the El Dorado Lease and Access Agreement (the "El Dorado Lease"). Under the El Dorado Lease, OpCo leases from Lion Oil the real property on which the El Dorado Terminal and Tank Assets are located. The El Dorado Lease has an initial term of 50 years with automatic renewal for a maximum of four successive 10-year periods thereafter.
El Dorado Site Services Agreement
. On February 10, 2014, in connection with the El Dorado Transaction, Lion Oil and OpCo entered into the El Dorado Site Services Agreement. Under the El Dorado Site Services Agreement, Lion Oil provides OpCo with shared use of certain services, materials and facilities that are necessary to operate and maintain the El Dorado Terminal and Tank Assets as currently operated and maintained. The term of the El Dorado Site Services Agreement is co-terminous with the El Dorado Lease discussed above.
2013 Developments
North Little Rock Acquisition
On October 24, 2013, we purchased a refined products terminal in Little Rock, Arkansas from Enterprise Refined Products Company LLC (the "North Little Rock Terminal"). The aggregate purchase price was approximately $5.0 million, which has been preliminarily allocated to property, plant and equipment and intangible assets. The preliminary valuation is subject to change during the purchase price allocation period.
Tyler Acquisition
On July 26, 2013, the Partnership completed the acquisition of the refined products terminal (the "Tyler Terminal") and 96 storage tanks and ancillary assets (the "Tyler Tank Assets") adjacent to the Tyler Refinery from Delek (the "Tyler Acquisition"). The Tyler Terminal, together with the Tyler Tank Assets, are sometimes hereinafter collectively referred to as the "Tyler Terminal and Tank Assets." The purchase price paid for the assets acquired was $94.8 million in cash. The assets acquired consisted of:
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The Tyler Terminal.
The refined products terminal located at the Tyler Refinery, which consists of a truck loading rack with nine loading bays supplied by pipeline from storage tanks, also owned by the Partnership, located adjacent to the Tyler Refinery, along with certain ancillary assets. Total throughput capacity for the terminal is approximately 72,000 bpd.
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The Tyler Tank Assets.
Ninety-six (96) storage tanks and certain ancillary assets (such as tank pumps and piping) located adjacent to the Tyler Refinery with an aggregate shell capacity of approximately 2.0 million barrels.
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The Tyler Acquisition was a transfer between entities under common control. Accordingly, the accompanying financial statements and related notes of the Predecessor and the Partnership have been retrospectively adjusted to include the historical results of the Tyler Terminal and Tank Assets for all periods presented through July 26, 2013, the date of the acquisition (the "Tyler Predecessor"). We refer to the historical results of the DKL Predecessor and the Tyler Predecessor collectively as our "Predecessors." See "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of Our Financial Results for additional information.
Hopewell Acquisition
On July 19, 2013, the Partnership purchased a 13.5 mile pipeline (the "Hopewell Pipeline") that originates at the Tyler Refinery and terminates at the Hopewell Station in Smith County, Texas, where it effectively connects to our 19-mile pipeline (the "Big Sandy Pipeline") that originates at the Hopewell Station and terminates at our light petroleum products terminal located in Big Sandy, Texas. The Hopewell Pipeline and the Big Sandy Pipeline form essentially one pipeline link between the Tyler Refinery and the Big Sandy Terminal (collectively, the Hopewell Pipeline and the Big Sandy Pipeline are referred to as the "Tyler-Big Sandy Pipeline"). The aggregate purchase price for the Hopewell Pipeline was approximately $5.7 million, which has been preliminarily allocated to property, plant and equipment and intangible assets. The preliminary valuation is subject to change during the purchase price allocation period.
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Amended and Restated Credit Facility
On July 9, 2013, we amended and restated our senior secured revolving credit agreement, which we originally entered into on November 7, 2012, with Fifth Third Bank, as administrative agent, and a syndicate of lenders (the "Amended and Restated Credit Agreement"). Under the terms of the Amended and Restated Credit Agreement, the lender commitments were increased from $175.0 million to $400.0 million and a dual currency borrowing tranche was added that permits draw downs in U.S. or Canadian dollars. The Amended and Restated Credit Agreement also contains an accordion feature whereby the Partnership can increase the size of the credit facility to an aggregate of $450.0 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent.
Borrowings denominated in U.S. dollars under the Amended and Restated Credit Agreement bear interest at either a U.S. dollar prime rate, plus an applicable margin, or the London Interbank Offered Rate ("LIBOR"), plus an applicable margin, at the election of the borrowers. Borrowings denominated in Canadian dollars under the Amended and Restated Credit Agreement bear interest at either a Canadian dollar prime rate, plus an applicable margin, or the Canadian Dealer Offered Rate ("CDOR") rate, plus an applicable margin, at the election of the borrowers. The applicable margin in each case varies based upon the Partnership's most recently reported leverage ratio.
Information About Our Segments
We prepare segment information on the same basis that we review financial information for operational decision-making purposes. Currently, our business consists of two operating segments: (i) our pipelines and transportation segment and (ii) our wholesale marketing and terminalling segment. Additional segment and financial information is contained in our segment results included in Item 6, Selected Financial Data; Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and
Note 13
, Segment Data, of our consolidated financial statements included in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.
Pipelines and Transportation Segment
Our pipelines and transportation segment consists of assets that provide crude oil gathering, crude oil and refined products transportation and crude oil, intermediates and refined products storage services primarily in support of Delek’s refining operations in Tyler, Texas and El Dorado, Arkansas. Additionally, this segment provides crude oil transportation services to certain third parties, including a major integrated oil company. In providing these services, we do not take ownership of the products or crude oil that we transport or store; and, therefore, we are not directly exposed to changes in commodity prices.
As of December 31, 2013, this segment consisted of assets primarily divided into six operating systems: (i) our Lion Pipeline System, (ii) our SALA Gathering System, (iii) our Paline Pipeline System, (iv) our East Texas Crude Logistics System (including the Nettleton Pipeline and McMurrey Pipeline Systems), (v) the Tyler-Big Sandy Pipeline and storage fees generated by the Big Sandy Terminal and (vi) the Tyler Tank Assets. Please see "Item 2—Properties—Our Asset Portfolio—Pipelines and Transportation Segment" for detailed descriptions of the assets that comprise these operating systems. The tables below show the operating results for each of our operating systems. For the years ended
December 31, 2013
and
2012
, we present the results of both the Partnership and our Predecessors, as delineated in any notes accompanying the tables, and for the year ended
December 31, 2011
, we present the results of only our Predecessors.
Lion Pipeline System.
Our Lion Pipeline System transports crude oil to, and refined products from, Delek's El Dorado Refinery. The pipelines in this system also have injection points where crude oil gathered from the SALA Gathering System is injected and then transported to the El Dorado Refinery. We do not charge an additional tariff for the transportation of these gathered crude oils over the Lion Pipeline System if a tariff has been charged for transportation on the SALA Gathering System. In addition, a pipeline within the Lion Pipeline System transports minimal crude oil for a third party. We own substantially all of these pipelines but do lease from an unrelated third party a small amount of capacity on a portion of the Lion Pipeline System which runs from El Dorado, Arkansas to our terminal in Memphis, Tennessee. The Lion Pipeline System and SALA Gathering System each have crude oil storage tanks and facilities ancillary to the operation of the pipeline system. The Lion Pipeline System is capable of transporting crude oil offloaded from rail cars at or near the El Dorado Refinery. The following table details certain operating data for our Lion Pipeline System.
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Average Daily Throughput (bpd)
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Year Ended
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December 31,
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2013
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2012
(1)
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2011
(1) (2)
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Delek Logistics Partners, LP
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DKL Predecessor
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DKL Predecessor
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Lion Pipeline System:
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Crude Oil Pipelines (Non-gathered)
(3)
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46,515
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46,027
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57,442
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Refined Products Pipelines to Enterprise System
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49,694
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45,220
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45,337
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(1)
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Throughputs for the year ended December 31, 2012 include the throughputs of the DKL Predecessor from January 1, 2012 through November 6, 2012 and those of the Partnership for the period beginning November 7, 2012 through December 31, 2012. Throughputs for the year ended December 31, 2011 include the throughputs of only the DKL Predecessor.
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(2)
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Throughputs for the year ended December 31, 2011 are for the 247 days Delek operated the El Dorado Refinery in 2011.
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(3)
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Excludes crude oil gathered on our SALA Gathering System and injected into our Lion Pipeline System.
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SALA Gathering System.
The SALA Gathering System primarily gathers and transports crude oil and condensate that is purchased by Delek or a third party to whom Delek has assigned its rights and from various crude oil producers in Arkansas, Texas and Louisiana. In addition, the gathering system transports small volumes of crude oil that is received from other sources and condensate that is purchased from a third party in east Texas. All such crude oil and other products are ultimately transported to Delek's El Dorado Refinery for processing. In addition, a pipeline within the SALA Gathering System transports minimal crude oil for a third party shipper. The table below sets forth historical throughput information for the SALA Gathering System.
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Average Daily Throughput (bpd)
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Year Ended
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December 31,
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2013
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2012
(1)
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2011
(1)
(2)
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Delek Logistics Partners, LP
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DKL Predecessor
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DKL Predecessor
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SALA Gathering System:
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Throughput (average bpd):
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22,152
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20,747
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17,676
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(1)
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Throughputs for the year ended December 31, 2012 include the throughputs of the DKL Predecessor from January 1, 2012 through November 6, 2012 and those of the Partnership for the period beginning November 7, 2012 through December 31, 2012. Throughputs for the year ended December 31, 2011 include the throughputs of only the DKL Predecessor.
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(2)
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Throughputs for the year ended December 31, 2011 are for the 247 days Delek operated the El Dorado Refinery in 2011.
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Paline Pipeline System.
Our Paline Pipeline System runs from Longview, Texas to Nederland, Texas and was initially a northbound crude oil pipeline. In 2011, prior to our purchase of the Paline Pipeline System, a major integrated oil company contracted with the prior owner of the Paline Pipeline System to reverse the pipeline to primarily run southbound. In exchange, the oil company agreed to pay for use of 100% of such southbound capacity through December 31, 2014. The agreement will renew automatically each year unless terminated by either party at least six months prior to the year end. For a more thorough discussion of this contract, please see "—Commercial Agreements—Other Agreements with Third Parties—Paline Pipeline System Capacity Reservation" and "Item 13—Certain Relationships and Related Transactions,
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and Director Independence" of this Annual Report on Form10-K. A three-mile portion of the Paline Pipeline System still runs northbound from Kilgore, Texas to Longview and is used by an unrelated third party to ship crude oil.
East Texas Crude Logistics System.
Our East Texas Crude Logistics System is comprised of the Nettleton and McMurrey Pipelines and their related tank farms. The Nettleton Pipeline is used to transport crude oil from our tank farms in and around Longview, Texas to the Bullard Junction at the Tyler Refinery. The McMurrey Pipeline also begins at our tank farms in and around Longview, Texas and then runs roughly parallel to the Nettleton Pipeline. The table below sets forth historical average daily throughput for the East Texas Crude Logistics System.
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Average Daily Throughput (bpd)
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Year Ended
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December 31,
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2013
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2012
(1)
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2011
(1)
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Delek Logistics Partners, LP
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DKL Predecessor
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DKL Predecessor
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East Texas Crude Logistics System (average bpd)
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19,896
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55,068
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55,341
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% of Tyler Refinery Crude Throughput
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34.1
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%
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97.6
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%
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98.8
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%
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(1)
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Throughputs for the year ended December 31, 2012 include the throughputs of the DKL Predecessor from January 1, 2012 through November 6, 2012 and those of the Partnership for the period beginning November 7, 2012 through December 31, 2012. Throughputs for the year ended December 31, 2011 include the throughputs of only the DKL Predecessor.
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In April 2013, a reconfigured pipeline system that is owned and operated by third parties began transporting crude oil to the Tyler Refinery from west Texas. Delek has a 10-year agreement, expiring in 2023, with such third parties to transport a substantial majority of the Tyler Refinery’s crude oil requirements on this reconfigured pipeline system. As a result of the third parties' ability to transport crude oil on its reconfigured pipeline system, the crude oil supplied through the Nettleton and McMurrey Pipelines fell below the minimum aggregate throughput requirements of our pipelines and tankage agreement with Delek during the second quarter of 2013 and remained below the minimum aggregate throughput requirements for the remainder of the
year ended
December 31, 2013
. Going forward, crude oil volumes transported on our East Texas Crude Logistics System will decrease from approximately 55,000 bpd to approximately 10,000 bpd or less. For so long as Delek is required to pay the associated minimum volume commitment under its commercial agreement with us relating to the East Texas Crude Logistics System, Delek will be obligated to pay us throughput fees in an amount equal to the fees it would pay were we to throughput 35,000 bpd, based on the per barrel fees in our agreement. To provide flexibility for our assets, we reconfigured a portion of the East Texas Crude Logistics System to be bi-directional, which enables it to transport crude oil from the west to Longview.
Tyler-Big Sandy Pipeline.
The Tyler-Big Sandy Pipeline is essentially one pipeline link between the Tyler Refinery and the Big Sandy Terminal that consists of the following two pipelines, which effectively connect at the Hopewell Station: (i) the Hopewell Pipeline, which
originates at the Tyler Refinery and terminates at the Hopewell Station and (ii) the Big Sandy Pipeline, which originates at the Hopewell Station and terminates at the Big Sandy Terminal. We acquired the Hopewell Pipeline in July 2013. It was not operational for a majority of the year ended
December 31, 2013
because the pipeline required maintenance to return it to service. The Hopewell Pipeline became operational in the fourth quarter of 2013, thus making the Tyler-Big Sandy Pipeline fully operational at that time. However, no product was throughput at the Big Sandy Terminal during this period.
Tyler Tank Assets.
The Tyler Tank Assets consist of 96 storage tanks and certain ancillary assets (such as tank pumps and piping) located adjacent to the Tyler Refinery with an aggregate shell capacity of approximately 2.0 million barrels. On
July 26, 2013
, in connection with the Tyler Acquisition, we and Delek entered into an eight-year throughput and tankage agreement with respect to the Tyler Terminal and Tank Assets. Under the agreement, Delek is subject to a
$841,667
per month storage fee for the right to use the active shell capacity of the Tyler Storage Tanks, which fee is adjusted for inflation in July of each year. See "Commercial Agreements—Commercial Agreements in Connection with the Tyler Acquisition" for additional detail.
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Wholesale Marketing and Terminalling Segment
Our wholesale marketing and terminalling segment provides wholesale marketing and terminalling services to Delek’s refining operations and to independent third parties from whom we receive fees for marketing, transporting, storing and terminalling refined products. As of December 31, 2013, we generated revenue in our wholesale marketing and terminalling segment by (i) providing marketing services for the refined products output of the Tyler Refinery, (ii) engaging in wholesale activity at our Abilene and San Angelo, Texas terminals, as well as at terminals owned by third parties, whereby we purchase light products from third parties for sale and exchange to third parties, and (iii) providing terminalling services to independent third parties and Delek. See "—Commercial Agreements—Commercial Agreements in Connection with the Offering—Terminalling" and "—Commercial Agreements—Other Agreements with Third Parties." The tables below show the operating results for the wholesale marketing and terminalling segment. For the years ended
December 31, 2013
and
2012
, we present the results of both the Partnership and our Predecessors, as delineated in any notes accompanying the tables, and for the year ended
December 31, 2011
, we present the results of only our Predecessors.
Wholesale Marketing
East Texas.
Pursuant to a marketing agreement with Delek, expiring in 2022, we market 100% of the refined products output of the Tyler Refinery, other than jet fuel and petroleum coke. Following the term, the marketing agreement automatically renews for successive one year terms unless either party provides notice of non-renewal 10 months prior to the expiration of the then-current term. Our services consist of identifying potential customers, negotiating and recommending for Delek’s approval purchase orders and supply contracts, monitoring anticipated sales volumes and inventories and serving as a point of contact for sales and marketing issues. The following table sets forth the historical sales volumes of the Tyler Refinery.
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Year Ended
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December 31,
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2013
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2012
(1)
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2011
(1)
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Delek Logistics Partners, LP
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DKL Predecessor
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DKL Predecessor
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Sales volumes (average bpd):
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Gasoline and gasoline blendstocks
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33,381
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30,143
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29,110
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Diesel/jet
(2)
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20,387
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20,875
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22,239
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Petrochemical, LPG, NGLs
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1,578
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1,820
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1,814
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Other
(2)
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3,427
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4,736
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3,884
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Total sales volumes
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58,773
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57,574
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57,047
|
||
|
(1)
|
Throughputs for the year ended December 31, 2012 include the throughputs of the DKL Predecessor from January 1, 2012 through November 6, 2012 and those of the Partnership for the period beginning November 7, 2012 through December 31, 2012. Throughputs for the year ended December 31, 2011 include the throughputs of only the DKL Predecessor.
|
|
(2)
|
Prior to November 7, 2012, the DKL Predecessor also marketed jet fuel and petroleum coke. Subsequent to November 7, 2012, we ceased to market jet fuel and petroleum coke for the Tyler Refinery. Accordingly, these amounts include jet fuel and petroleum coke for the DKL Predecessor for the year ended December 31, 2011 and through November 6, 2012. Jet fuel and petroleum coke are excluded from these amounts subsequent to November 7, 2012.
|
West Texas.
In our west Texas marketing operations, we generate revenue by purchasing refined products from independent third-party suppliers for sale and exchange to third parties at our San Angelo and Abilene, Texas terminals and at third-party terminals located elsewhere in Texas. Substantially all of our product sales in west Texas are on a wholesale basis.
Substantially all of our refined petroleum products for sale in west Texas during 2013 were purchased from two suppliers. Under a contract we have with Noble Petro, Inc. ("Noble Petro"), we have the right to purchase up to 20,350 bpd of refined petroleum products from Noble Petro (the "Abilene Contract"). Under the Abilene Contract, we purchase refined products based on monthly average prices from Noble Petro immediately prior to our resale of such products to customers at our San
9
Angelo and Abilene, Texas terminals, which we lease to Noble Petro. Under this arrangement, we have limited direct exposure to risks associated with fluctuating prices for these refined products due to the short period of time between the purchase and resale of these refined products. The Abilene Contract expires in December 2017 and does not have a renewal option.
In addition, in 2013, we had the right to purchase 7,000 bpd of refined products for resale at third-party terminals located in Aledo, Odessa and Frost, Texas along the Magellan Orion Pipeline pursuant to our contract (the "East Houston Contract") with Magellan Asset Services, L.P. ("Magellan"). We owned the inventory purchased under the East Houston Contract. The East Houston contract was terminated in January 2014. We are currently purchasing spot barrels from third parties for sale to wholesale customers on similar terms as we did under the East Houston Contract.
The following table details the average aggregate daily number of barrels of refined products, and the margins associated with such products, that we sold in our west Texas wholesale operations for the periods indicated.
|
2013
|
2012
(1)
|
2011
(1)
|
|||||||||
|
Delek Logistics Partners, LP
|
DKL Predecessor
|
DKL Predecessor
|
|||||||||
|
Throughput (average bpd)
(2)
|
18,156
|
|
16,523
|
|
15,493
|
|
|||||
|
Bulk Biofuels
(3)
|
—
|
|
5,577
|
|
3,022
|
|
|||||
|
Gross margin (in thousands)
(2)
|
$
|
12,420
|
|
$
|
15,512
|
|
$
|
8,488
|
|
||
|
Gross margin per barrel
(2)
|
$
|
2.12
|
|
$
|
2.56
|
|
$
|
1.50
|
|
||
|
(1)
|
Throughputs for the year ended December 31, 2012 include the throughputs of the DKL Predecessor from January 1, 2012 through November 6, 2012 and those of the Partnership for the period beginning November 7, 2012 through December 31, 2012. Throughputs for the year ended December 31, 2011 include the throughputs of only the DKL Predecessor.
|
|
(2)
|
Excludes bulk ethanol and biodiesel.
|
|
(3)
|
Prior to November 7, 2012, the DKL Predecessor also marketed bulk ethanol and biodiesel, beginning in the fourth quarter of 2011. Subsequent to November 7, 2012, we have not marketed bulk ethanol and biodiesel. Accordingly, these amounts are presented for the time period during which we marketed bulk biofuels.
|
Terminalling
We provide terminalling services for products to independent third parties and Delek through a light products terminal in Nashville, Tennessee and to Delek through our light products terminals in Memphis, Tennessee, Tyler, Texas, Big Sandy, Texas and North Little Rock, Arkansas. Delek has an agreement to use our Memphis terminal pursuant to a five-year terminalling agreement with us, which expires in November 2017. Delek, at its sole option, may extend the term for two renewal terms of five years each. Delek also has agreements to use our Tyler and North Little Rock terminals that expire in July and October of 2022, respectively, and Delek, at its sole option, may extend the term of each for two renewal terms of four years each. We also have contracted to provide exclusive terminalling and storage services to Delek at our light products terminal in Big Sandy, Texas pursuant to a five-year agreement, expiring July 2018. Delek, at its sole option, may extend the term for two renewal terms of five years each. This terminal was not operational for a majority of the year ended December 31, 2013, as the Hopewell Pipeline, which is necessary for the use of the terminal, was out of service due to maintenance needed on the pipeline; however, pursuant to the terms of the Big Sandy terminalling agreement, Delek was required to pay us a minimum fee based upon minimum storage and throughput amounts. See “—Commercial Agreements—Commercial Agreements in Connection with the Offering—Terminalling.” The Big Sandy terminal was available for use beginning in the fourth quarter 2013, but no product was throughput at the terminal during this period. The table below sets forth historical average daily throughput for our terminals.
10
|
Year Ended
|
|||||||||
|
December 31,
|
|||||||||
|
2013
(1)
|
2012
(2)
|
2011
(2) (3)
|
|||||||
|
Delek Logistics Partners, LP
|
DKL Predecessor
|
DKL Predecessor
|
|||||||
|
Throughput (average bpd):
|
|||||||||
|
Big Sandy, TX
(4)
|
—
|
|
—
|
|
—
|
|
|||
|
Memphis, TN
|
9,575
|
|
10,334
|
|
11,961
|
|
|||
|
Nashville, TN
|
6,270
|
|
5,086
|
|
5,946
|
|
|||
|
Tyler, TX
(5)
|
55,686
|
|
—
|
|
—
|
|
|||
|
North Little Rock, AR
(6)
|
3,907
|
|
—
|
|
—
|
|
|||
|
Total (average bpd)
|
75,438
|
|
15,420
|
|
17,907
|
|
|||
|
(1)
|
Throughputs for the year ended December 31, 2013 include the throughputs of the Tyler Predecessor.
|
|
(2)
|
Throughputs for the years ended December 31, 2012 and December 31, 2011 include the throughputs of the DKL Predecessor from January 1, 2012 through November 6, 2012 and those of the Partnership for the period beginning November 7, 2012 through December 31, 2012.
|
|
(3)
|
Throughputs for the year ended December 31, 2011 are for the 247 days Delek operated the El Dorado Refinery in 2011.
|
|
(4)
|
The Big Sandy Terminal was acquired by Delek Marketing-Big Sandy, LLC on February 7, 2012. The terminal was idle during the period ended December 31, 2012 and for the majority of the period ended December 31, 2013. The terminal was available for use beginning in the fourth quarter of 2013, but no product was throughput at the terminal during this period.
|
|
(5)
|
Throughputs for the year ended December 31, 2013 are for the 159 days the Partnership owned the Tyler Terminal.
|
|
(6)
|
Throughputs for the year ended December 31, 2013 are for the 69 days the Partnership owned the North Little Rock Terminal.
|
Commercial Agreements
Commercial Agreements in Connection with the Offering
The Partnership entered into various long-term, fee-based commercial agreements with Delek at the completion of the Offering. Except where noted, each of these agreements, described below, became effective on November 7, 2012, concurrent with the completion of the Offering. Each of these agreements includes minimum quarterly volume or throughput commitments and has tariffs or fees indexed to inflation, provided that the tariffs or fees will not be decreased below the initial amount. Fees under each agreement are payable to us monthly by Delek or certain third parties to whom Delek has assigned certain of its rights. For a discussion of a third party's involvement in certain agreements, see "El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement." In most circumstances, if Delek or the applicable third party assignee fails to meet or exceed the minimum volume or throughput commitment during any calendar quarter, Delek, and not any third party assignee, will be required to make a quarterly shortfall payment to us equal to the volume of the shortfall multiplied by the applicable fee. Carry-over of any volumes in excess of such commitment to any subsequent quarter is not permitted. Exceptions to this requirement that Delek make minimum payments under a given agreement can exist if (i) there is an event of force majeure affecting our asset, or (ii) after the first three years of the applicable commercial agreement's term (a) there is an event of force majeure affecting the applicable Delek asset or (b) if Delek shuts down the applicable refinery upon giving 12 months' notice, which such notice may only be given after the first two years of the applicable commercial agreement's term. In addition, Delek may terminate any of these agreements under certain circumstances.
Under each of these agreements, we are required to maintain the capabilities of our pipelines, storage facilities and terminals such that Delek or its assignee may throughput and/or store, as the case may be, specified volumes of crude oil and refined products. To the extent that Delek or its assignee is prevented by our failure to maintain such capacities from
11
throughputting or storing such specified volumes for more than 30 days per year, Delek's minimum throughput commitment will be reduced proportionately and prorated for the portion of the quarter during which the specified throughput capacity was unavailable, and/or the storage fee will be reduced, prorated for the portion of the month during which the specified storage capacity was unavailable. Such reduction would occur even if actual throughput or storage amounts were below the minimum volume commitment levels.
Each of the Partnership's commercial agreements with Delek entered into at the completion of the Offering, other than the marketing agreement described under "—East Texas," has an initial term of five years, which may be extended at the option of Delek for up to two additional five-year terms. The marketing agreement has an initial term of ten years and may be renewed annually, thereafter.
The tariffs, throughput fees and the storage fees under our agreements with Delek are subject to increase or decrease on July 1 of each year, by the amount of any change in the Federal Energy Regulatory Commission ("FERC") oil pipeline index or, in the case of the east Texas marketing agreement, to the consumer price index; provided, however, that in no event will the fees under any agreement be adjusted below the amount initially set forth in the applicable agreement.
Lion Pipeline and SALA Gathering Systems
.
We entered into a pipelines and storage facilities agreement with Delek under which we provide transportation and storage services to the El Dorado Refinery for crude oil and finished products. Under this pipelines and storage facilities agreement, Delek is obligated to meet certain minimum aggregate throughput volumes on the pipelines of our Lion Pipeline System and our SALA Gathering System as follows:
|
•
|
Lion Pipeline System
. The minimum throughput commitment on the Lion Pipeline System crude oil pipelines is an aggregate of
46,000
bpd (on a quarterly average basis) of crude oil shipped on the El Dorado, Magnolia and rail connection pipelines, other than crude oil volumes gathered on our SALA Gathering System, at a current tariff rate of
$0.89
per barrel. For the Lion Pipeline System refined products pipelines, the minimum throughput commitment is an aggregate of
40,000
bpd (on a quarterly average basis) of diesel or gasoline shipped on these pipelines at a current tariff rate of
$0.105
per barrel.
|
|
•
|
SALA Gathering System
. The minimum throughput commitment is an aggregate of
14,000
bpd (on a quarterly average basis) of crude oil transported on the SALA Gathering System at a current tariff rate of
$2.35
per barrel. Volumes initially gathered on the SALA Gathering System before injection into the Lion Pipeline System are not subject to an additional fee for transportation on our Lion Pipeline System to the El Dorado Refinery.
|
For a discussion of a third party's involvement in this agreement, see "—El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement."
East Texas Crude Logistics System
. We entered into a pipelines and tankage agreement with Delek pursuant to which we provide crude oil transportation and storage services for the Tyler Refinery. This agreement replaced the pipelines and tankage agreement between Delek and the DKL Predecessor. Under the current pipelines and tankage agreement, Delek is obligated to meet minimum aggregate throughput volumes of crude oil of at least
35,000
bpd, calculated on a quarterly average basis, on our East Texas Crude Logistics System for a current transportation fee of
$0.42
per barrel. For any volumes in excess of
50,000
bpd, calculated on a quarterly average basis, Delek is required to pay an additional fee currently at
$0.21
per barrel. In addition, Delek pays a current storage fee of
$261,480
per month for the use of our crude oil storage tanks along our East Texas Crude Logistics system.
East Texas
.
We entered into a marketing agreement with Delek pursuant to which we market 100% of the output of the Tyler Refinery, other than jet fuel and petroleum coke. This agreement replaced the marketing agreement between Delek and the DKL Predecessor and has a ten year initial term and automatically renews annually thereafter unless notice is given by either party ten months prior to the end of the then current term. Under the marketing agreement, Delek is obligated to make available to us for marketing and sale at our Tyler Terminal and/or our Big Sandy terminal an aggregate amount of refined products of at least
50,000
bpd, calculated on a quarterly average basis. In exchange for our marketing services, Delek pays us a base fee of
$0.6065
per barrel of products it sells. In addition, Delek has agreed to pay us 50% of the margin, if any, above an agreed base level generated on the sale as an incentive fee, provided that the incentive fee shall not be less than
$175,000
nor greater than
$500,000
per quarter.
Terminalling
. We entered into two five-year terminalling services agreements pursuant to which Delek pays us fees for providing terminalling and other services to Delek at our Memphis and Big Sandy terminals, as well as for storing product at our Big Sandy terminal. The minimum throughput commitments under these agreements are
10,000
bpd (on a
12
quarterly average basis) for the Memphis terminal, representing approximately
75%
of maximum loading capacity, and
5,000
bpd (on a quarterly average basis) for the Big Sandy terminal, representing approximately
55%
of maximum loading capacity, in each case currently at a fee of
$0.52
per barrel. For a discussion of a third party's involvement in the terminalling agreement relative to our Memphis Terminal, see "—El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement."
Even though the Big Sandy Terminal was not operational for a majority of the year ended
December 31, 2013
because the Hopewell Pipeline, which is necessary for the use of the terminal, was out of service due to the fact that the pipeline required maintenance in order to return it to service, Delek is required to pay us the minimum throughput fee based on a minimum of
5,000
bpd of refined products and a current minimum storage fee of
$52,250
per month. On July 19, 2013, we acquired the Hopewell Pipeline in order to effectively connect it with the Big Sandy Pipeline and thereby return the Big Sandy Terminal to operation. In the fourth quarter of 2013, operation of the Hopewell Pipeline was restored and the Big Sandy Terminal became available for use beginning in the fourth quarter of 2013, but no product was throughput at the terminal during this period.
Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline).
In connection with the acquisition of the Hopewell Pipeline, on July 25, 2013, we entered into the Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline) with Delek, which amended and restated the Terminalling Services Agreement (Big Sandy Terminal) dated November 7, 2012 to include, among other things, a minimum throughput commitment and a per barrel throughput fee that Delek must pay us for throughput along the Tyler-Big Sandy Pipeline. Upon effectiveness of the Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline), Delek became obligated to throughput a minimum aggregate volume of at least
5,000
bpd through the Tyler-Big Sandy Pipeline, calculated on a quarterly average basis, and to pay a current transportation fee of
$0.52
per barrel for volumes shipped on the pipeline in addition to its terminal throughput obligations, regardless of the fact that the Tyler-Big Sandy Pipeline was not operational until the fourth quarter of 2013.
Commercial Agreements in Connection with the Tyler Acquisition
On
July 26, 2013
, in connection with the Tyler Acquisition, we and Delek entered into a throughput and tankage agreement with respect to the Tyler Terminal and Tank Assets. Under the agreement, we agreed to provide Delek with throughput and storage services in return for throughput and storage fees. During each calendar quarter, Delek is obligated to throughput an aggregate amount of at least
50,000
bpd of certain refined products through the Tyler Terminal at a current throughput fee of
$0.35
per barrel (the "Throughput Fee"). Delek is also subject to a current fee of
$841,667
per month for the right to use the active shell capacity of the Tyler Storage Tanks. The fees under the agreement are indexed annually, on July 1, for inflation. The initial term of the agreement is eight years and Delek, at its sole option, may extend the term for two renewal terms of four years each. If Delek does not throughput the aggregate amounts equal to the minimum throughput commitments described above during any calendar quarter, Delek must pay us a shortfall payment equal to the shortfall volume multiplied by the Throughput Fee.
As set forth in the agreement, we are obligated to maintain certain throughput and storage capacities. Failure to meet such obligations may result in a reduction of fees payable by Delek to us under the agreement.
Tyler Lease and Access Agreement
. In connection with the Tyler Acquisition, we and Delek entered into a lease and access agreement with respect to the real property at the Tyler Terminal and Tank Assets. Under this agreement, we will lease from Delek the real property on which the Tyler Terminal and Tank Assets are located for
$100
annually, paid in advance, with an initial term of
50
years with automatic renewal for a maximum of four successive 10-year periods thereafter. The agreement gives Delek the right to access the property leased to us.
Tyler Site Services Agreement
. In connection with the Tyler Acquisition, we and Delek entered into a site services agreement. Under the site services agreement, Delek will provide us with shared use of certain services, materials and facilities that are necessary to operate and maintain the Tyler Terminal and Tank Assets as operated and maintained prior to our acquisition. We are subject to an initial annual service fee of
$0.2 million
with one-twelfth to be paid monthly to Delek. The annual service fee shall be adjusted on July 1 of each calendar year for inflation and may also increase by an amount equal to the actual cost to Delek of providing increased quantities of any items provided under this agreement. The term of the site services agreement is co-terminous with the lease and access agreement discussed above.
13
El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement
Pursuant to an arrangement with Delek and Lion Oil, to which we are not a party, J. Aron & Company ("J. Aron") acquires and holds title to substantially all crude oil and refined products transported on our Lion Pipeline System and SALA Gathering System. J. Aron is therefore considered the shipper for the liquid it owns on the Lion Pipeline System and the SALA Gathering System. J. Aron also has title to the refined products stored at our Memphis and North Little Rock terminals. Under (i) our pipelines and storage agreement with Lion Oil relating to the Lion Pipeline System and the SALA Gathering System, (ii) our terminalling agreements with Lion Oil relating to the Memphis and North Little Rock terminals, and (iii) our throughput and tankage agreement relating to the El Dorado Terminal and Tank Assets. Lion Oil has assigned to J. Aron certain of its rights under these agreements, including the right to have J. Aron's crude oil and intermediate and refined products stored in or transported on or through these systems, the Memphis and North Little Rock terminals and the El Dorado Terminal and Tank Assets, with Lion Oil acting as J. Aron's agent for scheduling purposes. Accordingly, even though this is effectively a financing arrangement for Delek whereby J. Aron sells the product back to Delek, J. Aron is technically our primary customer under each of these agreements. J. Aron will retain these storage and transportation rights for the term of its arrangement with Delek and Lion Oil, which currently runs through April 30, 2017, and J. Aron will pay us for the transportation, throughput and storage services we provide to it. The rights assigned to J. Aron will not alter Lion Oil's obligations to meet certain throughput minimum volumes under our agreements with respect to the transportation, throughputting and storage of crude oil and refined products through our facilities, but J. Aron's throughput will be credited toward Lion Oil's minimum throughout commitments. Accordingly, Lion Oil will be responsible for making any shortfall payments incurred under the pipelines and storage agreement or the terminalling agreement which may result from minimum throughputs or volumes not being met.
Other Agreements with Delek
In addition to the commercial agreements described above, the Partnership has entered into the following agreements with Delek:
Omnibus Agreement.
The Partnership entered into Omnibus Agreement with Delek upon the completion of the Offering. On July 26, 2013, in connection with the Tyler Acquisition, the Partnership entered into the First Omnibus Amendment. The First Omnibus Amendment included the following, among other things: (i) certain modifications in the reimbursement by Delek and certain of its subsidiaries for certain operating expenses and capital expenditures incurred by the Partnership or its subsidiaries, (ii) certain modifications of the indemnification provisions in favor of the Partnership with respect to certain environmental matters, and (iii) the increase of the annual administrative fee payable by us to Delek for corporate general and administrative services.
The annual administrative fee payable by the Partnership to Delek for corporate general and administrative services that Delek and its affiliates provide under the First Omnibus Amendment, increased from
$2.7 million
to
$3.0 million
, which is prorated and payable monthly. During the year ended
December 31, 2013
, we paid Delek approximately
$3.7 million
pursuant to the Omnibus Agreement, which includes
$2.8 million
related to general and administrative services and
$0.9 million
related to insurance coverage. Delek paid us approximately
$0.9 million
pursuant to the Omnibus Agreement during the year ended
December 31, 2013
as indemnification relative to the Paline Pipeline System.
Under the First Omnibus Amendment, Delek agreed to reimburse us for certain expenses that we incur for inspections, maintenance and repairs to any storage tanks we acquired in the Tyler Acquisition to cause such storage tanks to comply with applicable regulatory and/or industry standards. Delek also agreed to reimburse us for certain expenses that we incur for inspections, maintenance and repairs to any of the storage tanks contributed to us by Delek (subject to a deductible of
$0.5 million
per year) that are necessary to comply with the Department of Transportation ("DOT") pipeline integrity rules and certain American Petroleum Institute storage tank standards for a period of five years. Additionally, Delek was required to reimburse us for all non-discretionary maintenance capital expenditures with respect to the Tyler Terminal and Tank Assets in excess of
$0.4 million
for the period from July 26, 2013 through September 30, 2013. Delek was also required to reimburse us for non-discretionary maintenance capital expenditures with respect to all assets transferred from Delek to the Partnership in excess of
$1.35 million
for the period from September 30, 2013 through December 31, 2013.
On February 10, 2014, in connection with the El Dorado Transaction, the Partnership entered into the Second Omnibus Amendment. Under the Second Omnibus Amendment, Delek will reimburse us for all non-discretionary maintenance capital expenditures with respect to the El Dorado Terminal and Tank Assets in excess of $4.0 million for the period from February 10, 2014 through December 2014. In addition, Delek will reimburse us for non-discretionary maintenance capital expenditures with respect to certain assets transferred from Delek to the Partnership in excess of (i) $5.4 million for calendar year 2014; (ii) $9.8 million in any calendar year beginning with calendar year 2015 and ending with calendar year 2017;
14
and (iii) $4.4 million in any calendar year beginning with calendar year 2018 and ending February 2019. For more information regarding the Second Omnibus Amendment, see “Recent Developments—El Dorado Terminal and Tankage Acquisition.”
Operation and Management Services Agreement.
Our general partner operates our business on our behalf and is entitled under our partnership agreement to be reimbursed for the cost of providing those services. We and our general partner entered into an operation and management services agreement with Delek, pursuant to which our general partner uses employees of Delek to provide operational and management services with respect to our pipelines, storage and terminalling facilities and related assets, including operating and maintaining flow and pressure control, maintaining and repairing our pipelines, storage and terminalling facilities and related assets, conducting routine operational activities, and managing transportation and logistics, contract administration, crude oil and refined product measurement, database mapping, rights-of-way, materials, engineering support and such other services as our general partner and Delek may mutually agree upon from time to time. We and/or our general partner reimburse Delek for such services under the operation and management services agreement. In connection with the operations and management services agreement, we paid Delek approximately
$5.9 million
in
2013
.
On
July 26, 2013
, in connection with the Tyler Acquisition, the Partnership, our general partner and Delek Logistics Services Company terminated the operation and management services agreement. We will continue to reimburse our general partner for the services it provides to us under our partnership agreement. We reimbursed our general partner
$6.5 million
pursuant to the partnership agreement during the year ended
December 31, 2013
.
North Little Rock Terminalling Agreement.
On October 24, 2013, we purchased the North Little Rock Terminal from Enterprise Refined Products Company LLC. On the same date, we entered into an eight-year terminalling services agreement pursuant to which Delek pays us fees for providing terminalling and other services to Delek at the North Little Rock Terminal, and for storing product at the terminal. The minimum throughput commitments under this agreement are currently
8,100
bpd (on a quarterly average basis) at a fee of
$0.231
per barrel and a storage fee of
$63,000
per month. Pursuant to the agreement, we may complete certain capital projects in two phases in order to support and enhance blending activities and increase throughput capacity at the terminal. Upon completion of phase two capital projects, the minimum throughput fee will decrease to
$0.21
per barrel, while the storage fee will increase to
$99,000
per month and Delek’s minimum throughput commitment will increase to 15,500 bpd (on a quarterly average basis). The fees paid to us are indexed to inflation on July 1
st
of each year. For a discussion of a third party's involvement in this agreement, see "—El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement."
Other Agreements with Third Parties
Paline Pipeline System Capacity Reservation
.
In 2011, prior to our purchase of the Paline Pipeline System, a major integrated oil company contracted with the prior owner of the Paline Pipeline System to reverse the pipeline to primarily run southbound. In exchange, the oil company agreed to pay for the use of 100% of such southbound capacity for a fee of $450,000 and $529,250 per month in 2012 and 2013, respectively. Under the terms of the agreement, the monthly fee increased to approximately $535,700 in 2014. The agreement will thereafter be subject to annual escalation based on the change in the producer price index for finished goods during any renewal periods. The monthly fees payable to us under our agreement with this customer will increase proportionately to the extent throughput volumes are above 30,000 bpd. To the extent we are unable to provide our customer with 30,000 barrels of throughput capacity during a given month, the monthly fee may be reduced accordingly. The agreement extends through December 31, 2014 and will renew automatically each year unless terminated by either party at least six months prior to the year end.
Pursuant to the terms of the usage contract, this customer was required to make only payments of $229,000 per month for this capacity until the final segment of the reversal of the Paline Pipeline System was completed and we entered into a connection agreement with an affiliate of the customer to connect our system with such affiliate's tanks. We completed our work on the fourth segment of the reversal in October 2012. However, a connection agreement was not fully executed until April 2013, even though our customer had not yet completed the work on its tanks. Because we completed our necessary work, we believe we were owed the full payment under the contract beginning in November 2012 but our customer paid only $229,000 per month in 2012 and during the first quarter 2013. Pursuant to the Omnibus Agreement , Delek is required to indemnify us during the period from November 1, 2012 through December 31, 2013 for any lost service fees attributable to the failure of our customer to pay 100% of the full monthly fee. Therefore, Delek indemnified us for lost service fees related to the Paline Pipeline System in 2012 and during the first quarter 2013. Beginning in the second quarter 2013 and for the rest of 2013, we received the entire monthly amount payable to us of $529,250. Please see "—Other Agreements with Delek" and Item 13—"Certain Relationships and Related Transactions, and Director Independence" for additional discussion of this agreement.
15
West Texas.
In our west Texas marketing operations, we generated revenue by purchasing refined products from independent third-party suppliers for resale at our San Angelo and Abilene, Texas terminals, which we lease to Noble Petro, and at third-party terminals located elsewhere in Texas. Substantially all of our product sales in west Texas are on a wholesale basis. Substantially all of our petroleum products for sale in west Texas during 2013 were purchased from two suppliers. Under a contract with Noble Petro, we have the right to purchase up to 20,350 bpd of petroleum products for our Abilene, Texas terminal for sale and exchange at our Abilene and San Angelo, Texas terminals. Under this agreement, we purchase refined products based on monthly average prices from Noble Petro immediately prior to our resale of such products to customers at our San Angelo and Abilene terminals. We have limited direct exposure to risks associated with fluctuating prices for these refined products to the short period of time between the purchase and resale of these refined products. Our agreement with Noble Petro expires in December 2017 and has no renewal options. Previously, we had in 2013, the right to purchase up to an additional 7,000 bpd of refined products pursuant to a contract with Magellan at its East Houston terminal for resale at third-party terminals along the Magellan Orion Pipeline (the “East Houston Contract”). . This agreement was terminated in January 2014. We are currently purchasing spot barrels from third parties for sale to wholesale customers on similar terms as we did under the East Houston Contract.
Customers
We are dependent upon Delek as our primary customer and the loss of Delek as a customer would have a material adverse effect on both of our operating segments. We derive a substantial majority of our gross margin, which is defined as net sales less cost of goods sold, from fee-based commercial agreements with Delek. Even though Delek has assigned certain of its rights under several of these commercial agreements to J. Aron, this effectively amounts to a financing arrangement for Delek. For more information pertaining to Delek’s arrangement with J. Aron see "—El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement." For more information pertaining to these agreements, please see "—Commercial Agreements." We also have other customers, including major oil companies, independent refiners and marketers, jobbers, distributors, utility and transportation companies, and independent retail fuel operators.
Major Customer
One customer, Susser Petroleum Company ("Susser") accounted for
19.0%
of our total revenues in our wholesale marketing and terminalling segment during the year ended
December 31, 2013
. Delek accounted for
84.2%
of our total revenues in our pipelines and transportation segment during the year ended
December 31, 2013
. However, we believe that gross margin is a better measure of performance of our business than revenue, particularly in our wholesale marketing and terminalling segment, as total revenue varies with the price of the underlying product, such as a gallon of finished product. Accordingly, we believe that, for the purpose of evaluating our business on a customer-specific basis, gross margin, which we define as net sales less cost of goods sold, is a more accurate indicator to reflect the importance of certain customers to our operations.
Delek accounted for
72.2%
and
84.0%
of our gross margin in our wholesale and terminalling segment and our pipelines and transportation segment, respectively, in the year ended
December 31, 2013
. Delek accounted for
51.2%
and
57.3%
of the DKL Predecessor's gross margin in our wholesale marketing and terminalling segment in the years ended
December 31, 2012
and
2011
, respectively, and for
88.7%
and
46.0%
of our gross margin in our pipelines and transportation segment in the years ended
December 31, 2012
and
2011
, respectively.
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Competition
Pipelines and Transportation
Our business in this segment primarily consists of gathering, transporting and storing crude oil and finished products for Delek and third parties, especially other refiners. This business is very competitive. We face competition for the transportation and storage of crude oil from other pipeline owners whose pipelines or storage facilities (i) may have a location advantage over our pipelines or storage facilities, (ii) may be able to transport or store more desirable crude oil to Delek or to third parties, (iii) may be able to transport or store crude oil or finished product at a lower rate or (iv) may be able to store more crude oil or finished product than we can. In addition, Delek's or any of our third-party customers' wholesale customers could reduce their purchases of refined products due to the increased availability of more competitively priced product from other refiners or suppliers or for other reasons. Any or all such factors could cause Delek or our third-party customers to reduce throughput at their respective facilities or to reduce throughput to a level that is below the minimum throughput commitments established in any contracts we may have with them or to not renew such contracts when the term expires.
As a result of our physical integration with Delek's El Dorado Refinery and our contractual relationships with Delek relative to the El Dorado Refinery, we do not believe that we will face significant competition for the transportation of crude oil or refined products to or from the El Dorado Refinery, particularly during the term of our Lion Pipeline System and SALA Gathering System agreements with Delek. See "—Commercial Agreements—Commercial Agreements in Connection with the Offering—Lion Pipeline and SALA Gathering Systems."
Wholesale Marketing and Terminalling
The wholesale marketing and terminalling business is generally very competitive. Our owned refined product terminals, as well as the other third-party terminals we use to sell refined product, compete with other independent terminal operators as well as integrated oil companies on the basis of terminal location, price, versatility and services provided. The costs associated with transporting products from a loading terminal to end users usually limit the geographic size of the market that can be served economically by any terminal. Two key markets in west Texas that we serve from our owned facilities are Abilene and San Angelo, Texas. We have direct competition from an independent refinery that markets through another terminal in the Abilene market. However, there are no competitive fuel loading terminals within approximately 90 miles of our San Angelo terminal. Our Nashville terminal competes with a significant number of other terminals located in the greater Nashville area. With respect to terminalling services we provide to Delek at our Memphis and North Little Rock terminals, as a result of our exclusive terminalling agreements, we do not believe we will face significant competition from third parties for these services.
With respect to the marketing services we provide to Delek's Tyler Refinery, as a result of our exclusive 10-year agreement with Delek to market 100% of the refined products output of the Tyler Refinery other than jet fuel and petroleum coke, we do not believe that we will face significant competition for these services from third parties. In addition, as a result of our physical integration with the Tyler Refinery and our contractual relationships with Delek relative to the Tyler Refinery, we do not believe that we will face significant competition for the storage or throughput of intermediate or refined products at the Tyler Refinery, particularly during the term of our agreements with Delek. See "—Commercial Agreement—Commercial Agreements with in Connection with the Tyler Acquisition." Should Delek's wholesale customers, however, reduce their purchases of refined products due to the increased availability of more competitively priced products from other suppliers or for other reasons, the volumes we sell under the aforementioned agreement could decrease below the minimum volume commitment under the contract. Delek's Tyler Refinery is the only full-range product supplier within 100 miles, and we, therefore, believe its location gives the Tyler Refinery a natural advantage over more distant competitors.
Governmental Regulation and Environmental Matters
Rate Regulation of Petroleum Pipelines
The rates and terms and conditions of service on certain of our pipelines are subject to regulation by the FERC under the Interstate Commerce Act (“ICA”) and by the state regulatory commissions in the states in which we transport crude oil and refined products, including the Railroad Commission of Texas, the Louisiana Public Service Commission, and the Arkansas Public Service Commission. Certain of our pipeline systems are subject to such regulation and have filed tariffs with the appropriate entities. We also comply with the reporting requirements for these pipelines. Other of our pipelines have received a waiver from application of FERC's tariff requirements but will comply with other regulatory requirements.
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The FERC regulates interstate transportation under the ICA, the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including pipelines that transport crude oil and refined products in interstate commerce (collectively referred to as “petroleum pipelines”), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with the FERC. Under the ICA, shippers may challenge new or existing rates or services. The FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. The tariff rates provided for in our contracts are typically contractually subject to increase or decrease on July 1 of each year, by the amount of any change in FERC oil pipeline index or, in the case of the east Texas marketing agreement and the Tyler Throughput and Tankage Agreement to other inflation based indexes; provided, however, that in no event will the fees be adjusted below the amount initially set forth in the applicable agreement.
While the FERC regulates rates for shipments of crude oil or refined products in interstate commerce, state agencies may r
egulate rates and service for shipments in intrastate commerce.
We own pipeline assets in Texas, Arkansas, and Louisiana.
Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact-dependent and determined on a case-by-case basis.
We cannot provide assurance that the FERC will not at some point assert that some or all of the transportation service we provide, for which we do not have a tariff on file at FERC, is within its jurisdiction. If the FERC were successful with any such assertion, the FERC's ratemaking methodologies may subject us to potentially burdensome and expensive operational, reporting and other requirements. Currently, we own pipeline assets in Texas, Arkansas and Louisiana. In Texas, a pipeline, with some exceptions, is required to operate as a common carrier by publishing tariffs and providing transportation without discrimination. Arkansas provides that all intrastate oil pipelines are common carriers. In Louisiana, all pipelines conveying petroleum from a point of origin within the state to a destination within the state are declared common carriers. The Louisiana Public Service Commission is empowered with the authority to establish reasonable rates and regulations for the transport of petroleum by a common carrier, mandating public tariffs and providing of transportation without discrimination. State commissions have generally not been aggressive in regulating common carrier pipelines, have generally not investigated the rates or practices of petroleum pipelines in the absence of shipper complaints, and generally resolve shipper complaints informally.
Department of Transportation
The Pipeline and Hazardous Materials Safety Administration ("PHMSA") at the DOT regulates the design, construction, testing, operation, maintenance and emergency response of crude oil, petroleum products and other hazardous liquids pipelines and certain tank facilities. These requirements are complex, subject to change and, in certain cases, can be costly to comply with. We believe our operations are in substantial compliance with these regulations but cannot assure you that future requirements will not require substantial expenditures on our part to remain in compliance. Moreover, certain of these rules are difficult to insure adequately and we cannot assure you that we will have adequate insurance to address damages from any noncompliance.
On December 13, 2011, the United States Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or Pipeline Safety Act. The President signed the Pipeline Safety Act into law on January 3, 2012. Under the Pipeline Safety Act, maximum civil penalties for certain violations have been increased from $100,000 to $200,000 per violation per day, and from a total cap of $1 million to $2 million. A number of the provisions of the Pipeline Safety Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs. We believe any additional requirements resulting from these directives will not impact us differently than our competitors. We intend to work closely with our industry associations to participate with and monitor DOT-PHMSA's efforts.
The DOT has issued guidelines with respect to securing regulated facilities against terrorist attack. We have instituted security measures and procedures in accordance with such guidelines to enhance the protection of certain of our facilities. We cannot provide any assurance that these security measures would fully protect our facilities from an attack.
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Environmental Health and Safety
We are subject to various federal, state and local environmental and safety laws enforced by a number of regulatory agencies, including the U.S. Environmental Protection Agency ("EPA"), the U.S. Department of Transportation / Pipeline and Hazardous Materials Safety Administration, the U.S. Department of Labor / Occupational Safety and Health Administration, the Texas Commission on Environmental Quality, the Texas Railroad Commission, the Arkansas Department of Environmental Quality and the Tennessee Department of Environment and Conservation as well as other state and federal agencies. Numerous permits or other authorizations are required under these laws for the operation of our terminals, pipelines, storage tanks and related operations, and may be subject to revocation, modification and renewal.
These laws and permits create potential exposure to future claims and lawsuits involving environmental and safety matters, which could include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances that we manufactured, handled, used, released or disposed of, or that relate to pre-existing conditions for which we have assumed responsibility. We believe that our current operations are in substantial compliance with existing environmental and safety requirements. However, there have been and will continue to be ongoing discussions about environmental and safety matters between us and federal and state authorities, including notices of violations, citations and other enforcement actions, some of which have resulted or may result in changes to our operating procedures or capital expenditures. While it is often difficult to quantify future environmental or safety related expenditures, we anticipate that continuing capital investments and changes in operating procedures will be required for the foreseeable future to comply with existing and new requirements as well as evolving interpretations and more strict enforcement of existing laws and regulations.
Employees
We have no employees. Rather, we are managed by the directors and officers of our general partner. All of our general partner's executive management personnel are employees of Delek or a subsidiary of Delek and devote the portion of their time to our business and affairs that is required to manage and conduct our operations. Pursuant to the Second Omnibus Amendment, we pay an annual fee of
$3.3 million
for the provision of various centralized corporate services, including legal, accounting, information technology, and tax, among others, and we also reimburse Delek for other direct or allocated costs and expenses incurred by Delek on our behalf. In addition, our general partner operates our business on our behalf and is entitled under our partnership agreement to be reimbursed for the cost of providing those services.
We and our general partner also entered into an operation and management services agreement with Delek, pursuant to which our general partner uses employees of Delek to provide operational and management services with respect to our pipelines, storage and terminalling facilities and related assets, including day-to-day pipeline, terminal and logistics services and support and such other services and support as our general partner and Delek may mutually agree upon from time to time. We and/or our general partner must reimburse Delek for such services under the operation and management services agreement. Please see "—Commercial Agreements—Other Agreements with Delek—Operation and Management Services Agreement
".
On July 26, 2013, in connection with the Tyler Acquisition, the Partnership, our general partner and Delek Logistics Services Company terminated the operation and management services agreement. We will continue to reimburse our general partner for the services it provides to us under our partnership agreement.
Seasonality and Customer Maintenance Programs
The volume and throughput of crude oil and refined products transported through our pipelines and sold through our terminals and to third parties is directly affected by the level of supply and demand for all of such products in the markets served directly or indirectly by our assets. Supply and demand for such products fluctuates during the calendar year. Demand for gasoline, for example, is generally higher during the summer months than during the winter months due to seasonal increases in motor vehicle traffic, while demand for asphalt products, which is a substantial product of Delek's El Dorado Refinery, is lower in the winter months. In addition, our refining customers, such as Delek, occasionally slow or shut down operations to perform planned maintenance during the winter, when demand for their products is lower. Accordingly, these factors affect the need for crude oil or finished products by our customers and therefore limit our volumes or throughput during these periods, and our operating results are generally lower during the first and fourth quarters of the year. We, however, believe that many of the potential effects of seasonality on our revenues and contribution margin are substantially mitigated due to our commercial agreements with Delek that include minimum volume and throughput commitments.
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Available Information
Our internet website address is www.DelekLogistics.com. Information contained on our website is not part of this Annual Report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to such reports filed with (or furnished to) the Securities and Exchange Commission (“SEC”) are available on our internet website (in the “Investor Relations” section) free of charge, as soon as reasonably practicable after we file or furnish such material to the SEC. We also post our corporate governance guidelines, code of business conduct and ethics and the charter of the audit committee of the board of directors of our general partner in the same website location. Our governance documents are available in print to any unitholder that makes a written request to Secretary, Delek Logistics Partners, LP, 7102 Commerce Way, Brentwood, TN 37027.
ITEM 1A.
RISK FACTORS
Limited partner interests are inherently different from shares of capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were to occur, our business, financial condition or results of operations could be materially and adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units or the trading price of our common units could decline.
Risks Relating to Our Business
Delek, directly or indirectly accounts for a substantial majority of our margins. Therefore, we are indirectly subject to the business risks of Delek and J. Aron. If Delek or J. Aron changes its business strategy, fails to satisfy its obligations under our commercial agreements for any reason or significantly reduces the volumes transported through our pipelines or handled at our terminals or its use of our marketing services, our revenues, and, consequently, our margins would decline and our financial condition, results of operations, cash flows and ability to make distributions to our unitholders would be adversely affected.
Delek, directly or indirectly, accounted for
79.5%
of our gross margin for the year ended
December 31, 2013
. Delek is, effectively, through its supply and offtake agreement with its assignee, J. Aron, the principal customer for our Lion Pipeline System, our SALA Gathering System and our Memphis and North Little Rock terminals. Delek is the only customer for our Tyler Terminal and Tank Assets, our East Texas Crude Logistics System, our Big Sandy Terminal and our Tyler-Big Sandy Pipeline and effectively, through its supply and offtake agreement with J. Aron, is our only customer for our El Dorado Terminal and Tank Assets. See "Item 1—Business—Commercial Agreements—Commercial Agreements in Connection with the Offering," —Commercial Agreements—Commercial Agreements in Connection with the Tyler Acquisition" and "—Commercial Agreements—El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement." As we expect to continue to derive the substantial majority of our margins from Delek, either directly or indirectly, for the foreseeable future, we are subject to the risk of nonpayment, nonperformance or underperformance by Delek under our commercial agreements. In addition, we are subject to the risk of nonpayment, nonperformance or underperformance by Delek’s assignees, including without limitation, J. Aron. If Delek were to significantly decrease, or cause the significant decrease of, the throughput transported on our pipelines or the volumes of refined products handled at our terminals, whether because of business or operational difficulties or strategic decisions by Delek’s management, it is unlikely that we would be able to utilize any additional capacity on our pipelines or terminal facilities to service third-party customers without substantial capital outlays and delays, if at all, which could materially and adversely affect our results of operations, financial condition and cash flows. For example, a reconfigured third-party pipeline system began transporting crude oil to the Tyler Refinery from west Texas in April 2013. Delek has a 10-year agreement with such third parties to transport a substantial majority of the Tyler Refinery’s crude oil requirements on this reconfigured system. As a result, the crude oil supplied through the Nettleton and McMurrey Pipelines fell below the minimum aggregate throughput requirements during the second quarter of 2013 and remained below the minimum aggregate throughput requirements for the remainder of the
year ended
December 31, 2013
. Going forward, crude oil volumes transported on our East Texas Crude Logistics System will decrease from approximately 55,000 bpd to approximately 10,000 bpd as a result of this change. Additionally, any event, whether in our areas of operation or otherwise, that materially and adversely affects Delek’s, or its assignees', financial condition, results of operations or cash flows may adversely affect us and our business and therefore our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the operational and business risks of Delek and its assignees' including but not limited to the following:
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•
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the risk of contract cancellation, non-renewal or failure to perform by Delek’s customers, and Delek’s inability to replace such contracts, customers and/or revenues;
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•
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disruptions due to equipment interruption or failure at Delek’s facilities, or at third-party facilities on which Delek’s business is dependent;
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•
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the timing and extent of changes in commodity prices and the resulting demand for Delek’s refined products, and the availability and costs of crude oil and other refinery feedstocks;
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•
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the effects of economic downturns on Delek’s business and the business of its suppliers, customers, business partners and lenders;
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•
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Delek’s ability to remain in compliance with its supply and offtake arrangement with J. Aron;
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•
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Delek’s ability to remain in compliance with the terms of its outstanding indebtedness;
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•
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changes in the cost or availability of third-party pipelines, terminals and other means of delivering and transporting crude oil, feedstocks and refined products;
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•
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state and federal environmental, economic, health and safety, energy and other policies and regulations, and any changes in those policies and regulations;
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•
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environmental incidents and violations and related remediation costs, fines and other liabilities (including those that may arise from pending Department of Justice-led enforcement actions at the Tyler Refinery under the Clean Air Act; and
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•
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changes in crude oil and refined product inventory levels and carrying costs.
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Additionally, Delek continually considers opportunities presented by third parties with respect to its refinery assets. These opportunities may include offers to purchase certain assets and joint venture propositions. Delek may also change its refineries’ operations by constructing new facilities, suspending or reducing certain operations, or modifying or closing facilities. Changes may be considered to meet market demands, to satisfy regulatory requirements or environmental and safety objectives, to improve operational efficiency or for other reasons. Delek actively manages its assets and operations, and, therefore, changes of some nature, possibly material to its business relationship with us, could occur in the future.
Furthermore, conflicts of interest may arise between Delek and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. We have no control over Delek, and Delek may elect to pursue a business strategy that does not favor us or our business. Please see “—Risks Relating to Our Partnership Structure—Our general partner and its affiliates, including Delek, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.”
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.
In order to pay the minimum quarterly distribution of $0.375 per unit, or $1.50 per unit on an annualized basis, we will require available cash of approximately $9.4 million per quarter, or $37.7 million per year, based on the number of common, subordinated and general partner units that were outstanding at
December 31, 2013
and the phantom units with distribution equivalent rights that have been awarded to the independent directors of our general partner and certain key employees of our affiliates pursuant to our long-term incentive plan. We may not have sufficient available cash each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
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•
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the volume of crude oil and refined products we handle;
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•
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our entitlement to payments associated with minimum volume commitments;
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•
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the rates and terminalling and storage fees we charge for the volumes we handle;
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•
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the margins generated on the refined products we market or sell;
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•
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timely payments by our customers;
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•
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the level of our operating, maintenance and general and administrative expenses, including the administrative fee under the Omnibus Agreement and reimbursements to Delek for services provided to us; and
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•
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prevailing economic conditions.
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In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
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•
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the level and timing of capital expenditures we make and the timely reimbursement by Delek for any such expenditures for which it is required to reimburse us under the Omnibus Agreement;
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•
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the cost of acquisitions, if any;
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•
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our debt service requirements and other liabilities;
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•
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fluctuations in our working capital needs;
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•
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our ability to borrow funds and access capital markets;
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•
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restrictions on distributions contained in our debt agreements;
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•
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the amount of cash reserves established by our general partner; and
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•
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other business risks affecting our cash levels.
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The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow rather than our profitability. As a result, we may make cash distributions during periods when we record net losses, and we may not make cash distributions during periods when we record net income.
Our logistics and marketing operations and Delek’s refining operations are subject to many risks and operational hazards, some of which may result in business interruptions and shutdowns of our or Delek’s facilities and liability for damages. If a significant accident or event occurs that results in a business interruption or shutdown, our operations and financial results could be adversely affected.
Our logistics and marketing operations are subject to all of the risks and operational hazards inherent in gathering, transporting and storing crude oil and intermediate and refined and other products, including:
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damages to pipelines and facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism;
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•
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the inability of third-party facilities on which our operations are dependent, including Delek’s facilities, to complete capital projects and to restart timely refining operations following a shutdown;
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•
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mechanical or structural failures at our facilities or at third-party facilities on which our operations are dependent, including Delek’s facilities;
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•
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curtailments of operations as a result of severe seasonal weather;
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•
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inadvertent damage to pipelines from construction, farm and utility equipment;
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•
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constrained pipeline and storage infrastructure; and
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•
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other hazards.
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These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, as well as business interruptions or shutdowns of our facilities. Any such event or unplanned shutdown could have a material adverse effect on our business, financial condition and results of operations. In addition, Delek’s refining operations, on which our operations are substantially dependent and over which we have no control, are subject to similar operational hazards and risks inherent in refining crude oil. A significant accident at our facilities or at Delek’s facilities could expose us to significant liability and could affect Delek’s ability and/or obligation to satisfy the minimum volume commitments under our commercial agreements with Delek.
Significant portions of our pipeline systems and storage facilities have been in service for several decades. There could be service interruptions due to unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines and storage facilities that could have a material adverse effect on our business and results of operations.
Significant portions of our pipeline systems and storage and terminalling facilities and our SALA Gathering System have been in service for several decades, which could lead to service interruptions from failures or other events. The age and condition of our systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.
Each of our commercial agreements with Delek and its assignees and the agreement governing the capacity reservation on our Paline Pipeline System contain provisions that allow our counterparty to such agreement to suspend, reduce or terminate its obligations under such agreement in certain circumstances, including events of force majeure, which could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to unitholders.
Each of our commercial agreements with Delek and its assignees provides that Delek may suspend, reduce or terminate its obligations to us, including the requirement to pay the fees associated with the applicable minimum volume commitments, in the event of (i) a material breach of the agreement by us, (ii) Delek deciding to permanently or indefinitely suspend refining operations at one or more of its refineries, or (iii) the occurrence of certain force majeure events that would prevent us or Delek or its assignee from performing our or its obligations under the applicable agreement. As defined in our commercial agreements with Delek or its assignee, force majeure events include any acts or occurrences that prevent services from being performed either by us or Delek under the applicable agreement, such as:
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acts of God;
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strikes, lockouts or other industrial disturbances;
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acts of the public enemy, wars, blockades, insurrections, riots or civil disturbances;
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storms, floods or washouts;
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arrests or the order of any court or governmental authority having jurisdiction while the same is in force and effect;
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explosions, breakage, or accident to machinery, storage tanks or lines of pipe;
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any inability to obtain or unavoidable delay in obtaining material or equipment;
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any inability to deliver crude oil or refined products because of a failure of third-party pipelines; and
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any other causes not reasonably within the control of the party claiming suspension and which by the exercise of due diligence such party is unable to prevent or overcome.
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Delek has the discretion to decide to suspend, reduce or terminate its obligations under our commercial agreements notwithstanding the fact that its decision may significantly and adversely affect us.
Our customer for the southbound capacity of the Paline Pipeline System is also excused from performance of its obligations under its agreement with us in the event of a force majeure, including those events outlined above. Additionally, this customer may terminate its agreement with us if we breach the terms of the agreement and fail to remedy the breach within 90 days.
Accordingly, there exists a broad range of events that could result in our no longer being able to utilize our pipelines or terminals and the counterparty to the applicable commercial agreement no longer having an obligation to meet its minimum volume commitments or pay the amounts otherwise owing under the applicable agreement. Furthermore, a single event relating to one of Delek’s refineries could have such an impact on multiple of our commercial agreements with Delek or its assignee. Any reduction, suspension or termination of any of our commercial agreements could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to unitholders.
If Delek or its assignee satisfies only its minimum obligations under, or if we are unable to renew or extend, the various commercial agreements we have with it, our ability to make distributions to our unitholders may be impaired.
Neither Delek nor its assignee is obligated to use, or to pay us with respect to our services for volumes of crude oil or refined products in excess of the minimum volume commitments under the various commercial agreements with us. During refinery turnarounds, which typically last 30 to 60 days and are performed every three to five years, and during other planned or unplanned maintenance periods, Delek or its assignee may only satisfy its minimum volume commitments with respect to our assets that serve the refinery. A turnaround was completed at the El Dorado Refinery in February 2014 and a turnaround at the Tyler Refinery is scheduled for 2015. If Delek or its assignee had satisfied only its minimum volume commitments during the year ended
December 31, 2013
under each of the various commercial agreements with us, we would not have been able to make the full minimum quarterly distribution on all of our outstanding common units. In addition, the terms of Delek’s obligations under those agreements range from five to ten years unless earlier terminated as described above. If Delek or its assignee fails to use our services for volumes of crude oil or refined products in excess of the minimum volume commitments or to use our facilities and services after expiration of those agreements, or if Delek terminates those agreements prior to their expiration, and we are unable to generate additional revenues from third parties, our ability to make cash distributions to unitholders may be impaired. See “—Beginning in the first half of 2013, our East Texas Crude Logistics System began operating at levels significantly below Delek’s minimum volume commitment under its agreement with us and will remain at such levels for the foreseeable future.”
Beginning in the first half of 2013, our East Texas Crude Logistics System began operating at levels significantly below Delek’s minimum volume commitment under its agreement with us and will remain at such levels for the foreseeable future.
Our East Texas Crude Logistics System was the only pipeline system supplying crude oil to the Tyler Refinery prior to the second quarter of 2013. Beginning in April 2013, however, a reconfigured pipeline system that is owned and operated by third parties also began transporting crude oil to the Tyler Refinery from west Texas. Delek has a 10-year agreement with such third parties to transport a substantial majority of the Tyler Refinery’s crude oil requirements on this reconfigured system. Consequently, crude oil volumes transported on our East Texas Crude Logistics System decreased from approximately 55,000 bpd to approximately 10,000 bpd. For so long as Delek is required to pay the associated minimum volume commitment under its commercial agreement with us relating to the East Texas Crude Logistics System, Delek will be obligated to pay us throughput fees in an amount equal to the fees it would pay were we to throughput 35,000 bpd, based on the per barrel fees in our agreement. We did not realize incremental revenues associated with this fee structure following the commencement of third-party transportation to the Tyler Refinery.
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A material decrease in the refining margins at either of Delek’s refineries could materially reduce the volumes of crude oil or refined products that we handle, which could adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders.
The volumes of crude oil and refined products that we transport and refined products that we market depend substantially on Delek’s refining margins. Refining margins are dependent mostly upon the price of crude oil or other refinery feedstocks and the price of refined products. These prices are affected by numerous factors beyond our or Delek’s control, including the global supply and demand for crude oil, gasoline and other refined products. The current global economic uncertainty and high unemployment in the United States or other reasons could depress demand for refined products. The impact of low demand may be further compounded by excess global refining capacity and high inventory levels. Several refineries in North America and Europe have been temporarily or permanently shut down in response to falling demand and excess refining capacity.
If the demand for refined products, particularly in Delek’s primary market areas, decreases significantly, or if there were a material increase in the price of crude oil supplied to Delek’s refineries without an increase in the value of the refined products produced by those refineries, either temporary or permanent, which caused Delek to reduce production of refined products at its refineries, there would likely be a reduction in the volumes of crude oil and refined products we handle for Delek. Any such reduction could adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
In addition to our indirect exposure to Delek’s refining margins, we are directly impacted by the wholesale margins of the Tyler Refinery relative to U.S. Gulf Coast prices, where our marketing agreement with Delek provides that we share a portion of Delek’s margin, if any, above an agreed base level generated on the sale of refined products, other than jet fuel and petroleum coke. Accordingly, any decline in Delek's margins at the Tyler Refinery would negatively impact the revenues we generate under our marketing agreement and could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
A material decrease in the supply of attractively priced crude oil could materially reduce the volumes of crude oil and refined products that we transport and store, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
The volumes of crude oil and refined products that we may transport on our pipelines in excess of Delek’s minimum volume commitments will depend on the volumes of crude oil processed and refined products produced at Delek’s refineries. The volumes of crude oil processed and refined products produced depend, in part, on the availability of attractively priced crude oil.
In order to maintain or increase production levels at Delek’s refineries, Delek must continually contract for new crude oil supplies or consider connecting to alternative sources of crude oil. Adverse developments in major oil producing regions around the world could have a significantly greater impact on our financial condition, results of operations and cash flows because of our lack of industry and geographic diversity and substantial reliance on Delek as a customer. Accordingly, in addition to risks related to accessing, transporting and storing crude oil and refined products, we are disproportionately exposed to risks inherent in the broader oil and gas industry, including:
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the volatility and uncertainty of regional pricing differentials for crude oil and refined products;
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the ability of the members of the Organization of the Petroleum Exporting Countries, or OPEC, to agree to and maintain production controls;
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the nature and extent of governmental regulation and taxation; and
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the anticipated future prices of crude oil and refined products in markets served by Delek’s refineries.
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If, as a result of any of these or other factors, the volumes of attractively priced crude oil available to Delek’s refineries are materially reduced for a prolonged period of time, the volumes of crude oil and refined products that we transport and store, and the related fees for those services, could be materially reduced, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
Our substantial dependence on Delek's Tyler and El Dorado Refineries as well as the lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders.
We believe that a substantial majority of our contribution margin for the foreseeable future will be derived from the operation of our pipelines, gathering systems and terminal and storage facilities that support the Tyler and El Dorado Refineries and are primarily located in Arkansas and Texas and, to a lesser degree, Tennessee. Any event that renders either Delek refinery temporarily or permanently unavailable would likely have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders. Due to our lack of diversification in assets and geographic location, an adverse development in our businesses or areas of operations, including adverse developments due to
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catastrophic events, weather, regulatory action and decreases in demand for crude oil and refined products, could have a significantly greater impact on our results of operations and cash available for distribution to our common unitholders than if we maintained more diverse assets and locations. Such events may constitute force majeure events under our commercial agreements, potentially resulting in the suspension, reduction or termination of multiple commercial agreements in the affected geographic area. In addition, during planned maintenance periods or a refinery turnaround, we expect that Delek or its assignee may only satisfy its minimum volume commitments with respect to our assets that serve such refinery. Please see “—Each of our commercial agreements with Delek and the agreement governing the capacity reservation on our Paline Pipeline System contain provisions that allow our counterparty to such agreement to suspend, reduce or terminate its obligations under such agreement in certain circumstances, including events of force majeure, which would have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to unitholders” and “—If Delek satisfies only its minimum obligations under, or if we are unable to renew or extend, the various commercial agreements we have with Delek, our ability to make distributions to our unitholders may be impaired.”
Our ability to expand may be limited if Delek’s business does not grow as expected.
Part of our growth strategy depends on the growth of Delek’s business. For example, in our terminals and storage business, we believe our growth will be driven in part by identifying and executing organic expansion or new construction projects that will result in increased or new throughput volumes from Delek its assignees and third parties. Our prospects for organic growth currently include projects that we expect Delek to undertake, such as constructing new tankage, and that we expect to have an opportunity to purchase from Delek. In addition, our organic growth opportunities will be limited if Delek is unable to acquire new assets for which our execution of organic projects is needed. Additionally, if Delek focuses on other growth areas or does not make capital expenditures to fund the organic growth of its logistics operations, we may not be able to fully execute our growth strategy.
We may not be able to significantly increase our third-party revenue due to competition and other factors, which could limit our ability to grow and may increase our dependence on Delek.
Our ability to increase our third-party revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when third-party shippers require it. Under our commercial agreements with Delek, we may not provide service to third parties on our Lion Pipeline System, SALA Gathering System or East Texas Crude Logistics System, or at our Memphis or Big Sandy terminals, without Delek’s consent, subject to limited exceptions. In addition, our ability to obtain third-party customers on our East Texas Crude Logistics System will be dependent on our ability to make connections to third-party facilities and pipelines. If we do not or are unable to make connections to third-party facilities and pipelines, or if Delek prohibits us from doing so, the throughput on our East Texas Crude Logistics System will be limited to the demand from the Tyler Refinery not satisfied by third parties and the availability of crude oil shipped from third-party destinations. Furthermore, to the extent that we have capacity at our refined products terminals available for third-party volumes, competition from other existing or future refined products terminals owned by our competitors may limit our ability to utilize this available capacity.
We can provide no assurance that we will be able to attract material third-party revenues. Our efforts to establish our reputation and attract new unaffiliated customers may be adversely affected by our relationship with Delek and our desire to provide services pursuant to fee-based contracts. Our potential third-party customers may prefer to obtain services under contracts through which we could be required to assume direct commodity exposure.
The costs, scope, timelines and benefits of any construction projects we undertake may deviate significantly from our original plans and estimates.
One of our business strategies is to evaluate and make capital investments to expand our existing asset base through the development and construction of new or expanded logistics assets. At the same time, we also will need to devote significant resources to maintaining our asset base. However, in developing or maintaining such assets, we may experience unanticipated increases in the cost, scope and completion time for our construction or maintenance and repair projects. Equipment that we require to complete these projects may be unavailable to us at expected costs or within expected time periods. Additionally, labor expense may exceed our expectations. Due to these or other factors beyond our control, we may be unable to complete these projects within anticipated cost parameters and timelines. In addition, the benefits we realize from completed projects may take longer to realize and/or be less than we anticipated. Our inability to complete and/or realize the benefits of construction and/or maintenance projects in a cost-efficient and timely manner could have a material adverse effect on our business, financial condition, results of operations and our ability to make distributions.
If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase.
In order to expand our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. We will be required to use cash from our operations or incur borrowings
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or sell additional common units or other limited partner interests in order to fund our expansion capital expenditures. Using cash from operations will reduce cash available for distribution to our common unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. In connection with our cash distribution to Delek in connection with the Offering, we agreed to retain at least $90 million in outstanding debt, either under our credit facility or as a result of certain refinancings thereof, until November 2015. Therefore, the amount of funds we will be able to borrow under our credit facility until November 2015 will be limited by this outstanding amount. This may also limit our ability to obtain desired additional debt through this period. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. Moreover, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.
Delek’s level of indebtedness, the terms of its borrowings and any future credit ratings could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit profile. Our ability to obtain credit in the future and our future credit rating may also be affected by Delek’s level of indebtedness.
Delek has a significant amount of debt. As of
December 31, 2013
, Delek had total debt of $410.3 million, including current maturities of $33.7 million. In addition to its outstanding debt, as of
December 31, 2013
, letters of credit issued under Delek’s various credit facilities were $149.5 million. Delek’s significant level of debt could increase its vulnerability to general adverse economic and industry conditions and require Delek to dedicate a substantial portion of its cash flow from operations to service its debt and lease obligations, thereby reducing the availability of its cash flow to fund its growth strategy, including capital expenditures, acquisitions and other business opportunities. Furthermore, a higher level of indebtedness at Delek increases the risk that it may default on its obligations, including under its commercial agreements with us. In addition, a substantial portion of Delek’s debt has a variable rate of interest, which increases its exposure to interest rate fluctuations, to the extent it does not elect to hedge such exposures. The covenants contained in the agreements governing Delek’s outstanding and future indebtedness may limit its ability to borrow additional funds for development and make certain investments and may directly or indirectly impact our operations in a similar manner. For example, Delek’s indebtedness requires that any transactions it enters into with us must be on terms no less favorable to Delek than those that could have been obtained with an unrelated person. Furthermore, we have no control over whether Delek remains in compliance with the provisions of its credit arrangements or over the occurrence of certain events, except as such provisions or events may otherwise directly pertain to us or be under our control. There is also the risk that if Delek were to default under certain of its debt obligations, Delek’s creditors would attempt to assert claims against our assets during the litigation of their claims against Delek. The defense of any such claims could be costly and could materially impact our financial condition, even absent any adverse determination. In the event these claims were successful, our ability to meet our obligations to our creditors, make distributions and finance our operations could be materially and adversely affected.
Although we are not contractually bound by and are not liable for Delek’s debt under its credit arrangements, we are indirectly affected by certain prohibitions and limitations contained therein. Specifically, under the terms of certain of its credit arrangements, we expect that Delek will be in default if we incur any indebtedness for borrowed money in excess of $300.0 million at any time outstanding, which amount is subject to increase for (i) certain acquisitions of additional or newly constructed assets and for growth capital expenditures, in each case, net of asset sales, and for (ii) certain types of debt, such as debt obligations owed under hedge agreements, intercompany debt of the Partnership and our subsidiaries and debt under certain types of contingent obligations. Delek must also comply with certain financial covenants. Please see “Item 7— Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Agreements Governing Certain Indebtedness of Delek.” Due to its ownership and control of our general partner, Delek has the ability to prevent us from taking actions that would cause Delek to violate any covenants in its credit arrangements, or otherwise to be in default under any of its credit arrangements. In deciding whether to prevent us from taking any such action, Delek will have no fiduciary duty to us or our unitholders. Delek’s compliance with the covenants in its credit arrangements may restrict our ability to undertake certain actions that might otherwise be considered beneficial, including borrowing under our credit facility.
Any debt instruments that Delek or any of its affiliates enter into in the future, including any amendments to existing credit facilities, may include additional or more restrictive limitations on Delek that may impact our ability to conduct our business. These additional restrictions could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities.
Delek’s debt is not rated by any credit rating agencies. If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage or any future credit rating of Delek, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc. may consider the leverage and credit profile of Delek and its affiliates because of their ownership interest in and control of us and because Delek accounts for a substantial majority of our
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contribution margin. Any adverse effect on our credit rating would likely increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which could impair our ability to grow our business and make cash distributions to our unitholders.
Our insurance policies do not cover all losses, costs or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.
We are insured under the property, liability and business interruption insurance policies of Delek, subject to the deductibles and limits under those policies. To the extent Delek experiences losses under the insurance policies, the limits of our coverage may be decreased. In addition, we are not insured against all potential losses, costs or liabilities. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. In addition, because Delek’s business interruption policy does not cover losses for the first 21, 30, 45 or 60 days of the interruption, depending on the facility covered, a significant part or all of a business interruption loss could be uninsured. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
The energy industry is highly capital intensive, and the entire or partial loss of individual facilities or multiple facilities can result in significant costs to both energy industry companies, such as us, and their insurance carriers. In recent years, several large energy industry claims have resulted in significant increases in the level of premium costs and deductible periods for participants in the energy industry. For example, hurricanes in recent years have caused significant damage to several pipelines along the United States Gulf Coast. As a result of large energy industry claims, insurance companies that have historically participated in underwriting energy-related facilities may discontinue that practice, may reduce the insurance coverage they are willing to offer or demand significantly higher premiums or deductible periods to cover these facilities. If significant changes occur in the number or financial solvency of insurance underwriters for the energy industry, or if other adverse conditions over which we have no control prevail in the insurance market, we may be unable to obtain and maintain adequate insurance at a reasonable cost.
In addition, we cannot be assured that our insurers will renew our insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.
If third-party pipelines, terminals or other facilities interconnected to our pipeline systems or terminals become partially or fully unavailable, or if we are unable to fulfill our contractual obligations, our financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.
Our pipelines and terminals connect to other pipelines, terminals and facilities owned and operated by unaffiliated third parties, including ExxonMobil Corporation, Chevron Corporation, Enterprise Products Partners L.P. and others. The continuing operation of such third-party pipelines, terminals and other facilities is not within our control. For example:
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a substantial majority of the Lion Refinery’s finished product output is shipped on our Lion Pipeline System directly to the Enterprise TE Products Pipeline and its related terminal;
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all of the southbound volumes to be shipped on our Paline Pipeline System are delivered through a third-party terminal;
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the temporary suspension of crude oil shipments on a damaged pipeline owned by a third-party operator that began in April 2012 caused volumes on our Lion Pipeline System to be below historical volumes; and
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the Big Sandy terminal was not operational for a majority of the year ended December 31, 2013 because the Hopewell Pipeline, which is necessary for the use of the terminal and which was owned by a third party prior to our acquisition of the pipeline in July 2013, was out of service due to maintenance needed to restore the pipeline to operation; however, operation of the Hopewell Pipeline was restored subsequent to our acquisition of the pipeline and the Big Sandy terminal was available for use beginning in the fourth quarter of 2013.
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These pipelines, terminals and other facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity, corporate business decisions or because of damage from hurricanes or other operational hazards. In addition, we do not have interconnect agreements with all of these pipelines, terminals and other facilities and the interconnect agreements we do have may be terminated in certain circumstances, including circumstances beyond our control, and on short notice. If any of these pipelines, terminals or other facilities becomes unable to receive or transport crude oil or refined products, we may be unable to perform our obligations under our commercial agreements with Delek and third parties, and our financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.
Similarly, if additional shippers begin transporting volumes of refined products or crude oil over interconnecting pipelines, the allocations to us and other existing shippers on these interconnecting pipelines could be reduced, which could also reduce volumes distributed through our terminals or transported through our crude oil pipelines. Allocation reductions of this nature
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are not infrequent and are beyond our control. Any significant reduction in volumes would adversely affect our revenues and cash flow and our ability to make distributions to our unitholders.
An interruption or termination of supply and delivery of refined products to our wholesale marketing business could result in a decline in our sales and profitability.
In our west Texas wholesale marketing business, we sell refined products produced by refineries owned by unaffiliated third parties. In
2013
, we received substantially all of our supply of refined products for our west Texas wholesale business from two suppliers, Noble Petro and Magellan. In early 2014, our contract with Magellan was terminated. We could experience an interruption or termination of supply or delivery of refined products if our suppliers partially or completely ceased operations, temporarily or permanently, or ceased to supply us with refined products for any reason. The ability of these refineries and our suppliers to supply refined products to us could be disrupted by anticipated events such as scheduled upgrades or maintenance, as well as events beyond their control, such as unscheduled maintenance, fires, floods, storms, explosions, power outages, accidents, acts of terrorism or other catastrophic events, labor difficulties and work stoppages, governmental or private party litigation, or legislation or regulation that adversely impacts refinery operations. A reduction in the volume of refined products supplied to our wholesale business would likely adversely affect our sales and profitability.
We are exposed to the credit risks and certain other risks of our key customers, including Delek and its assignees, and any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers, including Delek or its assignees, could reduce our ability to make distributions to our unitholders.
If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. Any loss of our key customers, including Delek, could reduce our ability to make distributions to our unitholders.
Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.
Our revolving credit facility limits our ability to, among other things:
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incur or guarantee additional debt;
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incur certain liens on assets;
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dispose of assets;
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make certain cash distributions or redeem or repurchase units;
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change the nature of our business;
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engage in certain mergers or acquisitions;
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make certain investments and acquisitions; and
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enter into non arms-length transactions with affiliates.
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Our credit facility contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios can be affected by events beyond our control, and we cannot assure you that we will meet those ratios. In addition, our credit facility contains events of default customary for agreements of this nature, including the occurrence of a change of control (which will occur if, among other things, (i) Delek ceases to own and control legally and beneficially at least 51% of the equity interests of our general partner, (ii) Delek Logistics GP, LLC ceases to be our sole general partner or (iii) we fail to own and control legally and beneficially 100% of the equity interests of any other borrower under our credit facility, unless otherwise permitted thereunder).
The provisions of our credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest and other outstanding amounts, to be immediately due and payable. Such event of default would also permit our lenders to foreclose on our assets serving as collateral for our obligations under the credit facility. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. The credit facility also has cross-default provisions that will apply to any other material indebtedness we may have.
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Our debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.
As of
December 31, 2013
, we had
$164.8 million
in debt outstanding. This debt was incurred primarily in connection with (i) our cash distribution to Delek as part of the Offering, at which time we agreed to retain at least $90.0 million in outstanding debt, either under our credit facility or as a result of certain refinancings thereof, until November 2015; and (ii) the acquisition of the Tyler Terminal and Tank Assets in July 2013. We have the ability to incur additional debt; however, such ability is subject to limitations under our revolving credit facility. Our level of debt could have important consequences to us, including the following:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
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our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make payments on our debt and any interest thereon;
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we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our flexibility in responding to changing business and economic conditions may be limited.
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Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, which is within our control, or such as reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital, which actions we may not be able to effect on satisfactory terms or at all.
Increases in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Floating interest rates on our existing credit facility, to the extent not hedged, and interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Our right of first offer to acquire certain of Delek’s existing logistics assets and certain assets that it may acquire or construct in the future is subject to risks and uncertainty, and ultimately we may not acquire any of those assets.
The Omnibus Agreement provides us with a right of first offer on certain of Delek’s existing logistics assets and certain assets that it may acquire or construct in the future, subject to certain exceptions and time limitations. The consummation and timing of any future acquisitions pursuant to this right will depend on, among other things, Delek’s willingness to offer such assets for sale and obtain any necessary consents, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to such assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and Delek is under no obligation to accept any offer that we may choose to make. In addition, we may decide not to exercise our right of first offer if and when any assets are offered for sale, and our decision will not be subject to unitholder approval. In addition, our right of first offer may be terminated by Delek at any time in the event that it no longer controls our general partner.
If we are unable to make acquisitions on economically acceptable terms from Delek or third parties, our future growth could be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to make distributions to unitholders.
A portion of our strategy to grow our business and increase distributions to unitholders is dependent on our ability to make acquisitions that result in an increase in cash flow. If we are unable to make acquisitions from Delek or third parties, because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, we are unable to obtain financing for these acquisitions on economically acceptable terms, we are outbid by competitors or we or the seller are unable to obtain any necessary consents, our future growth and ability to increase distributions to unitholders may be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in cash flow. Any acquisition involves potential risks, including, among other things:
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mistaken assumptions about revenues and costs, including synergies;
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the assumption of unknown liabilities;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the overall costs of equity or debt;
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the diversion of management’s attention from other business concerns;
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unforeseen difficulties operating in new product areas or new geographic areas; and
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customer or key employee losses at the acquired businesses.
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If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
We may be unsuccessful in integrating the operations of the assets we have acquired or of any future acquisitions with our existing operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.
From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition, if at all. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and related repairs.
Certain of our pipeline facilities are subject to the pipeline safety regulations of PHMSA at the DOT. PHMSA regulates the design, construction, testing, operation, maintenance and emergency response of crude oil, petroleum products and other hazardous liquid pipeline facilities under 49 C.F.R. Part 195.
Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 ("PIPES Act"), PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for hazardous liquids pipelines located where a leak or rupture could affect “high consequence areas,” which are populated or environmentally sensitive areas. Pursuant to the PIPES Act, PHMSA issued regulations on May 5, 2011, that would, with limited exceptions, subject all low-stress hazardous liquids pipelines, regardless of location or size, to PHMSA’s pipeline safety regulations and would subject those low-stress hazardous liquids pipelines within one half mile of an environmentally sensitive area to the integrity management requirements. The integrity management regulations require operators, including us, to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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maintain processes for data collection, integration and analysis;
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repair and remediate pipelines as necessary; and
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implement preventive and mitigating actions.
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We may incur significant costs and liabilities associated with compliance with the pipeline safety regulations and any corresponding repair, remediation, preventive or mitigation measures required for our non-exempt pipeline facilities, including lost cash flows resulting from shutting down our pipelines during the pendency of such repairs.
In addition, changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a material adverse effect on us and similarly situated midstream operators. Many states have adopted regulations similar to existing DOT regulations for hazardous liquids pipelines within their state. These regulations can apply to pipeline facilities exempt from PHMSA jurisdiction as well as intrastate pipeline facilities subject to PHMSA jurisdiction, but for which the state has been certified by PHMSA to inspect, regulate and enforce the regulations for the intrastate facilities.
Should we fail to comply with PHMSA or applicable state regulations, we could be subject to penalties and fines.
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Our expansion of existing assets and construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
A portion of our strategy to grow and increase distributions to unitholders is dependent on our ability to expand existing assets and to construct additional assets. We have announced plans to increase the throughput capacity and diversify our product mix at the North Little Rock Terminal by completing certain capital projects that will expand the terminal and enhance its operational capabilities. The construction of a new pipeline or terminal or the expansion of an existing pipeline or terminal involves numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. If we undertake these types of projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, we may not receive sufficient long-term contractual commitments from customers to provide the revenue needed to support such projects. Even if we receive such commitments, we may not realize an increase in revenue for an extended period of time. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project, if at all. Moreover, we may construct facilities to capture anticipated future growth in production in a region or gain access to crude supplies at lower costs and such growth or access may not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition and our ability to make distributions to our unitholders.
We do not own all of the land on which our pipelines and several of our facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and terminal facilities or on which the Tyler Terminal and Tanks or the El Dorado Terminal and Tanks are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases, if such rights-of-way lapse or terminate or if our facilities are not properly located within the boundaries of such leases or rights-of-way. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we are unsuccessful in renegotiating rights-of-way, we may have to relocate our facilities. A loss of rights-of-way or a relocation could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to make distributions to our unitholders.
Whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline (for example, crude oil or refined products) and the laws of the particular state. In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located.
We operate in a highly regulated industry and increased costs of compliance with, or liability for violation of, existing or future laws, regulations and other requirements could significantly increase our costs of doing business, thereby adversely affecting our profitability.
Our industry is subject to extensive laws, regulations and other requirements including, but not limited to, those relating to the environment, safety, pipeline tariffs, employment, labor, immigration, minimum wages and overtime pay, health care and benefits, working conditions, public accessibility and other requirements. These laws and regulations are enforced by federal agencies including the EPA, the DOT / PHMSA, the Federal Motor Carrier Safety Administration, or FMCSA, the Occupational Safety and Health Act, or OSHA, and the FERC and state agencies such as the Texas Commission on Environmental Quality, the Railroad Commission of Texas, the Arkansas Department of Environmental Quality and the Tennessee Department of Environment and Conservation, as well as numerous other state and federal agencies. Ongoing compliance with, or a violation of, these laws, regulations and other requirements could have a material adverse effect on our business, financial condition and results of operations.
We believe that our operations are in substantial compliance with applicable laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions and construction bans or delays.
Under various federal, state and local environmental requirements, as the owner or operator of terminals and pipelines, we may be liable for the costs of removal or remediation of contamination at our existing locations, whether we knew of, or were responsible for, the presence of such contamination. We have incurred such liability in the past and some of our locations are the subject of ongoing remediation and/or monitoring projects. For example, on March 9, 2013, a release of crude oil was detected within a pumping facility at our Magnolia Station located west of the El Dorado Refinery and on October 7, 2013, a release of crude oil was identified from a gathering line near Macedonia, Arkansas. The failure to timely report and properly
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remediate contamination may subject us to liability to third parties and may adversely affect our ability to sell or rent our property or to borrow money using our property as collateral. Additionally, we may be liable for the costs of remediating third-party sites where hazardous substances from our operations have been transported for treatment or disposal, regardless of whether we own or operate that site. In the future, we may incur substantial expenditures for investigation or remediation of contamination that has not yet been discovered at our current or former locations or locations that we may acquire.
A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including the cost to comply with applicable laws and regulations, fines and penalties, natural resource damages and claims made by employees, neighboring landowners and other third parties for personal injury and property damage. We may experience future catastrophic sudden or gradual releases into the environment from our pipelines and terminals or discover historical releases that were previously unidentified or not assessed. Although our inspection and testing programs are designed to prevent, detect and address these releases promptly, any damages and liabilities incurred due to any future environmental releases from our assets have the potential to substantially affect our business.
Environmental regulation is becoming more stringent, and new environmental laws and regulations are continuously being enacted or proposed and interpretations of existing requirements may change from time to time. While it is impractical to predict the impact that future environmental, health and safety requirements or changed interpretations of existing requirements may have, such future activity may result in material expenditures to ensure our continued compliance. Such future activity could also adversely affect our ability to expand production or reduce demand for our products or services.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
Our operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, material modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.
Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating and capital costs and reduced demand for our products and services.
In December 2009, the EPA published its findings that emissions of greenhouse gases, or GHGs, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates GHG emissions from certain large stationary sources under the Clean Air Act Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. In addition, the EPA expanded its existing GHG emissions reporting rule to include onshore oil and natural gas processing, transmission, storage, and distribution activities, beginning in 2012 for emissions occurring in 2011. Congress has also from time to time considered legislation to reduce emissions of GHGs. Although it is not possible to predict the requirements of any GHG legislation that may be enacted, any laws or regulations that may be adopted to restrict or reduce GHG emissions may require us to incur increased operating costs. If we are unable to maintain sales of our refined products at a price that reflects such increased costs, there could be a material adverse effect on our business, financial condition and results of operations. Further, any increase in the prices of refined products resulting from such increased costs could have a material adverse effect on our business, financial condition or results of operations. Moreover, GHG regulation could also impact the consumption of refined products, thereby affecting the demand for our services.
In 2010, the EPA and the National Highway Transportation Safety Administration (NHTSA) finalized new standards, raising the required Corporate Average Fuel Economy, or CAFE, standard of the nation’s passenger fleet by 40% to approximately 35 miles per gallon by 2016 and imposing the first ever federal GHG emissions standards on cars and light trucks. In September 2011, the EPA and the Department of Transportation finalized first-time standards for fuel economy of medium and heavy duty trucks. On August 28, 2012, the EPA and NHTSA announced final regulations that mandated further decreases in passenger vehicle GHG emissions and increases in fuel economy beginning with 2017 model year vehicles and increasing to the equivalent of 54.5 miles per gallon by 2025. Such increases in fuel economy standards and potential electrification of the vehicle fleet, along with mandated increases in use of renewable fuels discussed above, could result in decreasing demand for petroleum fuels. Decreasing demand for petroleum fuels could materially affect profitability at Delek’s refineries and convenience stores, which could adversely impact our business, results of operations and cash flows.
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Our operations are subject to federal and state laws and regulations relating to product quality specifications, and we could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of products we distribute to meet certain quality specifications.
Various federal and state agencies prescribe specific product quality specifications for refined products, including vapor pressure, sulfur content, ethanol content and biodiesel content. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For example, mandated increases in use of renewable fuels could require the construction of additional storage and blending equipment. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions to our unitholders could be adversely affected. Violations of product quality laws attributable to our operations could subject us to significant fines and penalties as well as negative publicity. In addition, changes in the product quality of the products we receive on our pipeline system could reduce or eliminate our ability to blend products.
If our general partner or Delek loses any of its key personnel, our general partner's ability to manage our business on our behalf and continue our growth could be negatively impacted.
Our future performance depends to a significant degree upon the continued contributions of our general partner's officers and key technical personnel of Delek. Neither we nor our general partner nor Delek currently maintains key person life insurance policies for any of such persons. The loss or unavailability to us of any of these officers or key technical employees could significantly harm us. Our general partner and Delek face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of any of our general partner's officers and/or the key technical personnel would be unavailable for any reason, we or our general partner or Delek would be required to hire other personnel to manage and operate our business. We cannot be assured that we, our general partner or Delek would be able to locate or employ such qualified personnel on acceptable terms or at all.
A terrorist attack on our assets, or threats of war or actual war, may hinder or prevent us from conducting our business.
Terrorist attacks in the United States, as well as events occurring in response or similar to or in connection with such attacks, including political instability in various Middle Eastern countries, may harm our business. Energy-related assets (which could include pipelines and terminals such as ours) may be at greater risk of future terrorist attacks than other possible targets in the United States. In addition, the State of Israel, where Delek Group, the former parent company of Delek, is based, has suffered armed conflicts and political instability in recent years. We may be more susceptible to terrorist attack as a result of our connection to an Israeli owner. In the future, certain of the directors of our general partner may reside in Israel.
A direct attack on our assets, Delek’s assets or the assets of others used by us could have a material adverse effect on our business, financial condition and results of operations. In addition, any terrorist attack or continued political instability in the Middle East could have an adverse impact on energy prices, including prices for the crude oil and other feedstocks we transport and refined petroleum products, and an adverse impact on the margins from our operations. Disruption or significant increases in energy prices could also result in government-imposed price controls.
Further, changes in the insurance markets attributable to terrorist attacks could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital, including our ability to repay or refinance debt.
Our customers’ operating results are seasonal and generally lower in the first and fourth quarters of the year. Our customers depend on favorable weather conditions in the spring and summer months.
The volume and throughput of crude oil and refined products transported through our pipelines and sold through our terminals and to third parties is directly affected by the level of supply and demand for all of such products in the markets served directly or indirectly by our assets. Supply and demand for such products fluctuate during the calendar year. Demand for gasoline, for example, is generally higher during the summer months than during the winter months due to seasonal increases in motor vehicle traffic, while demand for asphalt products, which is a substantial product of Delek's El Dorado Refinery, is lower in the winter months. In addition, our refining customers, such as Delek, occasionally slow or shut down operations to perform planned maintenance during the winter, when demand for their products is lower. Accordingly, these factors can affect the need for crude oil or finished products by our customers and therefore limit our volumes or throughput during these periods, and could adversely affect our customers’ business, financial condition and results of operations, which may adversely affect our business, financial condition and results of operations.
Our exposure to direct commodity price risk and interest rate risk may increase in the future. We may incur losses as a result of our forward contract activities and derivative transactions.
Although we intend to enter into fixed-fee contracts with new transportation and terminalling customers in the future, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges or other fixed-fee arrangements
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and therefore have a greater exposure to fluctuations in commodity price risk than our current operations. Increased future exposure to the volatility of commodity prices could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.
To partially mitigate the risk of various financial exposures inherent in our business, including commodity price risk and interest rate risk, we selectively use derivative financial instruments, such as fuel-related derivative transactions, interest rate swaps and interest rate cap agreements. In connection with such derivative transactions, we may be required to make payments to maintain margin accounts and to settle the contracts at their value upon termination. The maintenance of required margin accounts and the settlement of derivative contracts at termination could cause us to suffer losses or limited gains. In particular, derivative transactions could expose us to the risk of financial loss upon unexpected or unusual variations in the sales price of wholesale gasoline. We cannot assure you that the strategies underlying these transactions will be successful. If any of the instruments we utilize to manage our exposure to various types of risk is not effective, we may incur losses.
Regulations adopted by the Commodity Futures Trading Commission could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The U.S. Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), a comprehensive financial reform legislation that, among other things, establishes comprehensive federal oversight and regulation of over-the-counter derivatives and many of the entities that participate in that market. Although the Dodd-Frank Act was enacted on July 21, 2010, the Commodity Futures Trading Commission (“CFTC”), and the SEC, along with certain other regulators, must promulgate final rules and regulations to implement many of the Dodd-Frank Act's provisions relating to over-the-counter derivatives. While some of these rules have been finalized, others have not; and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain. There can be no assurance that, if implemented, the new regulatory regime will not have a material adverse effect on our ability to hedge our exposure to commodity prices.
We rely on information technology in our operations, and any material failure, inadequacy, interruption or security failure of that technology could harm our business.
We inherited information technology systems and controls that monitor the movement of petroleum products through our pipeline systems, and also continue to rely on the information technology systems of Delek with respect to certain aspects of our operations. Information technology system failures, network disruptions (whether intentional by a third party or due to natural disaster), breaches of network or data security, or disruption or failure of the network system used to monitor and control pipeline operations could result in environmental damage, operational disruptions, regulatory enforcement or private litigation. Our computer systems, including our back-up systems, could be damaged or interrupted by power outages, computer and telecommunications failures, computer viruses, internal or external security breaches, events such as fires, earthquakes, floods, tornadoes and hurricanes, or errors by our employees. Further, the failure to operate effectively any of our systems or systems of Delek that are used in connection with our operations, or problems we or Delek may experience with transitioning to upgraded or replacement systems, could significantly harm our business and operations and cause us to incur significant costs to remediate such problems. In addition, a security compromise of our or Delek's internal data network may have disruptive impacts that could range from inconvenience in accessing business information to a disruption in our pipeline or terminal operations. Cost increases may be incurred in this area to combat the continued escalation of hacking and/or disruptive criminal activity.
There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition and results of operations.
Transportation on certain of our pipelines is subject to federal or state rate and service regulation, and the imposition and/or cost of compliance with such regulation could adversely affect our operations and cash flows available for distribution to our unitholders.
The rates and terms and conditions of service on certain of our pipelines are subject to regulation by the FERC under the Interstate Commerce Act and by the state regulatory commissions in the states in which we transport crude oil and refined products, including the Railroad Commission of Texas, the Louisiana Public Service Commission and the Arkansas Public Service Commission. Certain of our pipeline systems are subject to such regulation and have filed tariffs with the appropriate entities. We also comply with the reporting requirements for these pipelines. Other of our pipelines have received a waiver from application of FERC's tariff requirements but will comply with other regulatory requirements.
We filed tariffs with the FERC for service on the SALA Gathering System, the Magnolia Pipeline System, the El Dorado Pipeline System and a pipeline that is part of our Lion Oil System and is currently used by one shipper. We have been granted a waiver of FERC's tariff filing requirements for service on the East Texas Crude Logistics System, but remain subject to certain reporting requirements. The FERC regulates interstate transportation under the ICA, the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates and terms and conditions of service for interstate service on oil pipelines, including pipelines that transport crude oil and refined
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products in interstate commerce (collectively referred to as “petroleum pipelines”), be just, reasonable and not unduly discriminatory or preferential. The ICA also requires that such rates and terms and conditions of service be filed with the FERC. Under the ICA, shippers may challenge new or existing rates or services. The FERC is authorized to suspend the effectiveness of a challenged rate that has not yet become effective for up to seven months, though rates are typically not suspended for the maximum allowable period. If the FERC determines that a protested rate is unjust and unreasonable, the FERC will order refunds of amounts charged in excess of the just and reasonable rate. If the FERC determines that a rate challenged by complaint is unjust and unreasonable, reparations may be due for two years prior to the date of the complaint. If any challenge were successful, among other things, the rates that we charge under the tariffs that we intend to file could be reduced and such reductions could have a material adverse effect on our business, results of operations, financial condition and ability to make quarterly cash distributions to our unitholders.
The FERC currently permits, but does not require, regulated pipelines to increase their rates by a percentage factor equal to the change in the producer price index for finished goods plus 2.65 percent. Application of this index factor establishes a change in maximum allowable rate. Interested parties are permitted to protest a proposed index rate increase, and we cannot guarantee that the FERC will accept any such proposed increase if it is protested. In the event the index factor decreases in a given year, we may be required to reduce our rates if they exceed the new maximum allowable rate. The FERC’s indexing methodology is subject to review every five years; the current methodology will remain in place through June 30, 2016. Application of the FERC’s current or any revised indexing methodology may be insufficient to allow us to recover our actual increases in costs. If application of the indexing methodology does not permit a pipeline to recover its costs, the FERC’s regulations generally permit the pipeline to request a rate increase based on its actual cost of service. We cannot guarantee that any such proposed rate increase would be accepted.
The FERC has granted a waiver of the tariff filing and reporting requirements imposed under the ICA for the East Texas Crude Logistics System. The East Texas Crude Logistics System remains subject to the FERC’s jurisdiction under the ICA and is subject to the requirement to maintain books and records in accordance with FERC accounting requirements; we intend to comply with that requirement. If the facts upon which the waiver is based change materially (for example, if an unaffiliated shipper seeks access to our pipelines), the FERC typically requires that pipelines inform it of such changes, which may result in revocation of the waiver. If the FERC in the future revokes the waiver, we will be required, among other things, to file tariffs for service on the East Texas Crude Logistics System. If we file tariffs, we may be required to provide a cost justification for the transportation charge. We would also be required to provide service to all prospective shippers making reasonable requests for service without undue discrimination and to operate in a manner that does not provide any undue preference to shippers. The rates under such tariffs may be insufficient to allow us to recover fully our cost of providing service on the affected pipelines, which could adversely affect our business, financial condition and results of operations. In addition, regulation by the FERC may subject us to potentially burdensome and expensive operational, reporting and other requirements.
The Federal Trade Commission, the FERC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.
While the FERC regulates rates and terms and conditions of service for transportation of crude oil or refined products in interstate commerce by pipeline, state agencies may regulate rates and terms and conditions of service for petroleum pipeline transportation in intrastate commerce. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact-dependent and determined on a case-by-case basis. We cannot provide assurance that the FERC will not at some point assert that some or all of the transportation service we provide is within its jurisdiction. If the FERC were successful with any such assertion, its rate-making methodologies may subject us to potentially burdensome and expensive operational, reporting and other requirements. We own pipeline assets in Texas, Arkansas and Louisiana. In Texas, a pipeline, with some exceptions, is required to operate as a common carrier and provide transportation without discrimination. Arkansas provides that all intrastate oil pipelines are common carriers, but it exercises light-handed regulation over petroleum pipelines. In Louisiana, all pipelines conveying petroleum from a point of origin within the state to a destination within the state are declared common carriers. The Louisiana Public Service Commission is empowered with the authority to establish reasonable rates and regulations for the transport of petroleum by a common carrier, mandating public tariffs and providing of transportation without discrimination. State commissions have generally not been aggressive in regulating common carrier pipelines, have generally not investigated the rates or practices of petroleum pipelines in the absence of shipper complaints, and generally resolve complaints informally. If the regulatory commissions in the states in which we operate change their policies and aggressively regulate the rates or terms of service of pipelines operating in those states, it could adversely affect our business, financial condition and results of operations.
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Risks Relating to Our Partnership Structure
Our general partner and its affiliates, including Delek, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.
Delek controls our general partner and appoints all of the officers and directors of our general partner. In addition, three members of the board of directors of our general partner, each of whom also serve as executive officers of Delek, own a small percentage of our general partner. All of the officers and three of the directors of our general partner are also officers and/or directors of Delek. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to Delek. Conflicts of interest will arise between Delek and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Delek over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
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Neither our partnership agreement nor any other agreement requires Delek to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery or what markets to pursue or grow. The directors and officers of Delek have a fiduciary duty to make these decisions in the best interests of the stockholders of Delek, which may be contrary to our interests. Delek may choose to shift the focus of its investment and growth to areas not served by our assets.
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Delek, as our primary customer, has an economic incentive to cause us not to seek higher service fees, even if such higher fees could be obtained in arm’s-length, third-party transactions. Furthermore, under our commercial agreements, Delek’s consent is required before we may enter into an agreement with any third party with respect to our assets that serve the El Dorado and Tyler Refineries, and Delek has an incentive to cause us not to pursue such third-party contracts in certain circumstances.
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Our general partner is allowed to take into account the interests of parties other than us, such as Delek, in resolving conflicts of interest.
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All of the officers and three of the directors of our general partner are also officers and/or directors of Delek and will owe fiduciary duties to Delek. These officers will also devote significant time to the business of Delek and will be compensated by Delek accordingly.
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Delek may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests.
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Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.
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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
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Disputes may arise under our commercial agreements with Delek.
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Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash available for distribution to our unitholders.
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Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units. In addition, the inability of Delek to suspend or reduce its obligations under its commercial agreements with us or to claim a force majeure event in certain circumstances increases the likelihood of the conversion of the subordinated units.
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Our general partner determines which costs incurred by it are reimbursable by us.
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Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.
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Our partnership agreement permits us to classify up to $25.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated or general partner units or to our general partner in respect of the incentive distribution rights.
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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
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Our general partner intends to limit its liability regarding our contractual and other obligations.
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Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
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Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including Delek’s obligations under the First Omnibus Amendment and its commercial agreements with us.
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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
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Our general partner may transfer its incentive distribution rights without unitholder approval.
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Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
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Delek may compete with us.
Delek may compete with us. Under the First Omnibus Amendment, Delek and its affiliates have agreed not to engage in, whether by acquisition or otherwise, the business of owning or operating crude oil or refined products pipelines, terminals or storage facilities in the United States that are not within, directly connected to, substantially dedicated to, or otherwise an integral part of, any refinery owned, acquired or constructed by Delek. This restriction, however, does not apply to:
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any assets that were owned by Delek upon the completion of the Offering (including replacements or expansions of those assets);
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any asset or business that Delek acquires or constructs that has a fair market value of less than $5.0 million; and
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any asset or business that Delek acquires or constructs that has a fair market value of $5.0 million or more if we have been offered the opportunity to purchase the asset or business for fair market value not later than six months after completion of such acquisition or construction, and we decline to do so.
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As a result, Delek has the ability to construct assets which directly compete with our assets. The limitations on the ability of Delek to compete with us are terminable by either party if Delek ceases to control our general partner.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and Delek. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders.
If unitholders are not eligible holders, their common limited partner units may be subject to redemption.
We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible holders are limited partners whose (i) federal income tax status is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or an analogous regulatory body and (ii) nationality, citizenship or other related status would not create a substantial risk of cancellation or forfeiture of any property in which we have an interest, in each case as determined by our general partner with the advice of counsel. If you are not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, your units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders and, to the extent not otherwise reserved for, will rely primarily upon operating cash flows, from borrowings under the Amended and Restated Credit Agreement and potential future issuances of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per-unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitations in any of our credit facilities, on our ability to issue additional units, including units ranking senior to the common limited partner units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
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Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common limited partner units with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
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how to allocate corporate opportunities among us and its other affiliates;
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whether to exercise its limited call right;
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whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;
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how to exercise its voting rights with respect to the units it owns;
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whether to exercise its registration rights;
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whether to elect to reset target distribution levels;
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whether to transfer the incentive distribution rights to a third party; and
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whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
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Our partnership agreement restricts the remedies available to holders of our common limited partner units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
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whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our Partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
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our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
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our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
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approved by the Conflicts Committee of the Board of Directors of our general partner, although our general partner is not obligated to seek such approval;
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approved by the vote of a majority of the outstanding common limited partner units, excluding any common units owned by our general partner and its affiliates;
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determined by the Board of Directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
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determined by the Board of Directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
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In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or its Conflicts Committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the Conflicts Committee and the Board of Directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth subbullets above, then it will be presumed that, in making its decision, the Board of Directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
The administrative services fee and reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce our cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.
Prior to making any distribution on our common limited partner units, we will reimburse our general partner and its affiliates, including Delek, for costs and expenses they incur and payments they make on our behalf. Under the First Omnibus Amendment, we will pay Delek an annual fee and reimburse Delek and its subsidiaries for Delek’s provision of various centralized corporate services. Additionally, we will reimburse Delek for direct or allocated costs and expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses. We also expect to incur incremental annual general and administrative expense as a result of being a publicly traded partnership. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders.
Holders of our common limited partner units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its Board of Directors. Rather, the Board of Directors of our general partner will be appointed by Delek. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common limited partner units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Even if holders of our common limited partner units are dissatisfied, they cannot remove our general partner without its consent.
Unitholders are unable to remove our general partner without its consent because our general partner and its affiliates, including Delek, own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common and subordinated limited partner units voting together as a single class is required to remove our general partner. As of
December 31, 2013
, Delek owned
60.0%
of our outstanding common and subordinated limited partner units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common limited partner units and any existing arrearages on our common limited partner units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common limited partner units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable to us or any limited partner for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of unitholder dissatisfaction with the performance of our general partner in managing the Partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common limited partner units.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common limited partner units.
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates,
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their transferees and persons who acquired such units with the prior approval of the Board of Directors of our general partner, cannot vote on any matter.
Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.
Our partnership agreement does not restrict the ability of Delek to transfer all or a portion of its general partner interest or its ownership interest in our general partner to a third party. Our general partner, or the new owner of our general partner, would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers of our general partner.
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of Delek selling or contributing additional assets to us, as Delek would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
We may issue additional units without unitholder approval, which would dilute unitholder interests
Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common limited partner units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common limited partner units or other equity securities of equal or senior rank will have the following effects:
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our existing unitholders’ proportionate ownership interest in us will decrease;
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the amount of cash available for distribution on each unit may decrease;
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because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
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because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per-unit distribution on common limited partner units remains the same;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of the common limited partner units may decline.
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Delek may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common limited partner units.
Delek holds
2,799,258
common limited partner units and
11,999,258
subordinated limited partner units. All of the subordinated limited partner units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. In addition, we have agreed to provide Delek with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our general partner has a limited call right that may require our unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of our common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated
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pursuant to the terms of our partnership agreement. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any positive return on their investment. Our unitholders may also incur a tax liability upon any such sale of their units to Delek. At
December 31, 2013
, Delek owned approximately
2,799,258
common limited partner units, or
23.0%
of our total outstanding common limited partner units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Delek will indirectly own approximately 61.3% of our outstanding common limited partner units.
Our general partner, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common limited partner units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
The holder or holders of a majority of the incentive distribution rights, which is currently our general partner, have the right, at any time when there are no subordinated units outstanding and such holders have received incentive distributions at the highest level to which they are entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions.
In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the incentive distribution rights will be entitled to receive, in the aggregate, the number of common limited partner units equal to that number of common limited partner units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common limited partner units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common limited partner units to our general partner in connection with resetting the target distribution levels.
Our unitholders' liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. The Partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Our unitholders could be held liable for any and all of our obligations as if they were general partners if a court or government agency were to determine that:
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we were conducting business in a state but had not complied with that particular state’s partnership statute; or
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our unitholders' right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
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Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common limited partner units are liable both for the obligations of the transferor to make contributions to the
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Partnership that were known to the transferee at the time of transfer and for those obligations that were unknown if the liabilities could have been determined from the Partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Our common limited partner units are listed on the New York Stock Exchange ("NYSE"). Because we are a publicly traded limited partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common limited partner units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to such unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reductions in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common limited partner units.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such additional tax on us by a state will reduce the cash available for distribution to our unitholders. Our partnership agreement provides that, if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common limited partner units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common limited partner units may be modified by administrative, legislative or judicial interpretation at any time. From time to time members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. For example, one recent legislative proposal would eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any proposals will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common limited partner units.
Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.
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Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on such unitholder's share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
If the IRS contests the federal income tax positions we take, the market for our common limited partner units may be adversely impacted and the cost of any IRS contest would likely reduce our cash available for distribution to unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed herein or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse effect on the market for our common limited partner units and the price at which they trade. In addition, our costs of any contest with the IRS would be borne indirectly by our unitholders and our general partner because the costs would likely reduce our cash available for distribution.
Tax gain or loss on the disposition of our common limited partner units could be more or less than expected.
If any of our unitholders sells their common limited partner units, such unitholders must recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and such unitholder's tax basis in those common limited partner units. Because distributions in excess of such unitholder's allocable share of our net taxable income decrease such uniholder's tax basis in such unitholder's common limited partner units, the amount, if any, of such prior excess distributions with respect to the common limited partner units such unitholder sells will, in effect, become taxable income if such unitholder sells such common limited partner units at a price greater than its tax basis in those common limited partner units, even if the price such unitholder receives is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of such unitholder's common limited partner units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells their common limited partner units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common limited partner units that may result in adverse tax consequences to them.
Investment in our common limited partner units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common limited partner units.
We treat each holder of common limited partner units as having the same tax benefits without regard to the actual common limited partner units held. The IRS may challenge this treatment, which could adversely affect the value of the common limited partner units.
Because we cannot match transferors and transferees of common limited partner units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder's sale of common limited partner units and could have a negative impact on the value of our common limited partner units or result in audit adjustments to such unitholder's tax returns.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among
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transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Our counsel has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations.
A unitholder whose common limited partner units are loaned to a “short seller” to cover a short sale of common limited partner units may be considered as having disposed of those common limited partner units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common limited partner units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common limited partner units are loaned to a “short seller” to cover a short sale of common limited partner units may be considered as having disposed of the loaned common limited partner units, such unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common limited partner units during the period of the loan to the short seller and may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common limited partner units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common limited partner units could be fully taxable as ordinary income. Therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common limited partner units.
We will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common limited partner units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common limited partner units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common limited partner units and could have a negative impact on the value of the common limited partner units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any 12-month period will result in the termination of our Partnership for federal income tax purposes.
We will be considered to have technically terminated our Partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includable in such unitholder's taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the Partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
As a result of investing in our common limited partner units, our unitholders may be subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which
44
we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in Arkansas, Louisiana, Tennessee and Texas. Arkansas and Louisiana impose a personal income tax on individuals, and each of the four states imposes an income or similar tax on corporations and certain other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
PROPERTIES
Our Asset Portfolio
Our principal assets, as of
December 31, 2013
, are described below under the segment that uses such assets. We believe that our assets are adequate for our operations and adequately maintained.
Pipelines and Transportation Segment
Our pipelines and transportation segment consists of approximately 400 miles of operable crude oil transportation pipelines, 48 miles of refined product pipelines and approximately 600 miles of crude oil gathering and trunk lines. Associated with and currently used in connection with the operation of these lines are crude oil storage tanks with an aggregate of approximately 4.1 million barrels of active shell capacity.
Lion Pipeline System.
Our Lion Pipeline System primarily consists of (i) the Magnolia Pipeline system, (ii) the Magnolia Station located west of the El Dorado Refinery, (iii) the El Dorado Pipeline system, (iv) two refined product pipelines, (v) three small crude oil pipelines used by Delek and an unrelated third party, (vi) multiple short crude oil pipelines that are located on the El Dorado Refinery and the Sandhill Station owned by Delek adjacent to the El Dorado Refinery and transport all crude oil from the incoming pipelines in the Lion Pipeline System and the SALA Gathering System to and from a 150,000 barrel capacity storage tank, known as Tank 192 and (vii) Tank 192.
The Magnolia Pipeline is a 77-mile crude oil pipeline, with a capacity of 68,500 bpd, that runs from a connection with ExxonMobil’s North Line pipeline near Shreveport, Louisiana to our Magnolia Station, where the crude oil is then stored and transferred to our El Dorado Pipeline. J. Aron is the shipper on the Magnolia Pipeline. In addition, a new third-party pipeline linked an existing third-party pipeline to the Magnolia Pipeline near Haynesville, Louisiana, which allowed for the receipt of crude oil transported from Longview, Texas. The Magnolia Pipeline is regulated by the FERC.
The Magnolia Station has approximately 135,000 barrels of active shell capacity.
The El Dorado Pipeline is a 28-mile, 12-inch crude oil pipeline, with a capacity of approximately 22,000 bpd, that transports crude oil from our Magnolia Station to the Sandhill Station owned by Delek, which is adjacent to the El Dorado Refinery. The El Dorado Pipeline is regulated by the FERC. J. Aron is the shipper on this pipeline. Upon reaching the Sandhill Station, the crude oil from the El Dorado Pipeline is transported, via multiple short crude oil pipelines owned by us, to Tank 192. At present, substantially all crude that enters the El Dorado Refinery, including the crude gathered on the SALA Gathering System, is routed through these short pipelines to Tank 192. Tank 192 is located at Delek's Sandhill Station. We own Tank 192 and lease the underlying ground from Lion Oil under a long term ground lease.
We also own two refined product pipelines that transport gasoline and diesel from the El Dorado Refinery to the nearby Enterprise TE Products Pipeline (the “Refined Products Pipeline System”). Pursuant to a capacity lease with Enterprise TE Products Pipeline Company LLC dated October 24, 2013, service on the Refined Products Pipeline System now extends to the OpCo refined products terminal in Memphis, TN. The diesel line is 12 inches in diameter while the gasoline line is 10 inches in diameter. These two lines commence at the El Dorado Refinery. We own the portion of these lines that commence at the Sandhill Station at the location of the pump for each line and runs approximately eight miles to the Enterprise TE Products Pipeline. From this point, service continues on the capacity leased from Enterprise TE Products Pipeline Company LLC to the OpCo terminal in Memphis, TN. The Refined Products Pipeline System is regulated by the FERC.
We also own three other short crude oil pipelines. One of these lines is a common carrier pipeline and is regulated by the FERC. At present it only transports a small volume of crude oil for a third-party specialty products refiner in the area. The other two pipelines transport crude oil for Delek, which is delivered to the El Dorado Refinery via railcars.
45
Magnolia Pipeline System
El Dorado Pipeline System
SALA Gathering System.
The SALA Gathering System includes approximately 600 miles of two- to eight-inch crude oil gathering and transportation lines in southern Arkansas and northern Louisiana located primarily within a 60-mile radius of the El Dorado Refinery. The SALA Gathering System primarily gathers crude oil production from multiple fields in southern
46
Arkansas and northern Louisiana for delivery to the El Dorado Refinery both directly and through the El Dorado Pipeline System.
SALA Gathering System
The SALA Gathering System includes 54 crude oil storage tanks and breakout tanks with a total combined active shell capacity of approximately 0.8 million barrels (including Tank 192 and the 122,000 barrels of capacity discussed below), 14 truck receipt locations, approximately 500 pipeline gathering and receiving stations and 17 relay stations to deliver crude oil to the El Dorado Pipeline System or directly to the El Dorado Refinery. We also have 0.5 million barrels of combined shell capacity that is currently not in service. In addition, we own 122,000 barrels of shell capacity that we allow a third party to utilize pursuant to a 10-year agreement.
47
Paline Pipeline System.
The Paline Pipeline System is primarily a 195-mile, 10-inch crude oil pipeline, with a capacity of approximately 36,000 bpd, running from Longview, Texas to the Chevron-operated Beaumont terminal in Nederland, Texas. It includes an approximately seven-mile idle pipeline from Port Neches to Port Arthur, Texas and a three-mile section that runs north from Kilgore, Texas. The three-mile section of pipeline is a common carrier pipeline and is regulated by the FERC. At present it only transports a small volume of crude oil for an unrelated third-party.
Paline Pipeline System
48
East Texas Crude Logistics System
. Our East Texas Crude Logistics System includes two owned and operated crude oil pipeline systems serving the Tyler Refinery: (i) the Nettleton pipeline, a 36-mile pipeline, with a capacity of 38,000 bpd, that transports crude oil from Nettleton Station to the Tyler Refinery and (ii) the McMurrey Pipeline System, a 65-mile pipeline system, with a capacity of 28,000 bpd, that transports crude oil from inputs between our La Gloria Station and the Tyler Refinery.
East Texas Crude Logistics System
Our East Texas Crude Logistics System also includes the following owned or leased crude oil storage terminals at which we store crude oil owned by Delek for the Tyler Refinery.
|
Active
|
||||
|
Aggregate Shell
|
||||
|
Storage
|
||||
|
Terminal
|
Number of Tanks
|
Capacity (bbls)
|
||
|
La Gloria Station
|
2
|
|
450,000
|
|
|
Nettleton Station
(1)
|
5
|
|
165,000
|
|
|
Bradford Station
(1)
|
2
|
|
65,000
|
|
|
Arp Station
|
2
|
|
110,000
|
|
|
Big Sandy Station
|
7
|
|
248,000
|
|
|
Total
|
18
|
|
1,038,000
(2)
|
|
49
|
(1)
|
Located on property that we lease from a third party as described in more detail below under “—Facilities.”
|
|
(2)
|
In addition, we have 55,000 barrels of shell capacity that is currently not in service and would require additional costs to return to service.
|
Tyler-Big Sandy Pipeline
Hopewell Pipeline.
The Hopewell Pipeline is a an approximately 13-mile pipeline, with a capacity of 26,000 bpd, that originates at the Tyler Refinery and terminates at the Hopewell Station in Smith County, Texas where it effectively connects to the Big Sandy Pipeline.
Big Sandy Pipeline.
The Big Sandy Pipeline is a 19-mile pipeline, with a capacity of 26,000 bpd, that originates at the Hopewell Station and terminates at the Big Sandy Station in Big Sandy, Texas.
The Hopewell Pipeline and the Big Sandy Pipeline form essentially one pipeline link between the Tyler Refinery and our light petroleum products terminal located in Big Sandy, Texas (the "Tyler-Big Sandy Pipeline").
Tyler Tank Assets
Tyler Tank Assets.
Our Tyler Terminal has 96 storage tanks and certain ancillary assets (such as tank pumps and piping) with an aggregate shell capacity of approximately 2.0 million barrels.
Wholesale Marketing and Terminalling Segment
Wholesale Marketing
We own approximately 104 miles of product pipelines in west Texas that connect our San Angelo and Abilene, Texas terminals to the Magellan Orion Pipeline. These pipelines include the following:
|
•
|
a 13.2-mile, eight-inch pipeline from a Magellan Pipeline custody transfer point at Magellan's Tye Station to the Abilene terminal;
|
|
•
|
a 13.5-mile, four-inch pipeline from the Abilene terminal to the Delek Pipeline tie-in;
|
|
•
|
a 76.5-mile, six-inch pipeline system from Delek's Tye Station to the San Angelo terminal; and
|
|
•
|
a 1.0-mile, 20-inch pipeline from Magellan's Tye Station to Delek's Tye Station.
|
Each of these pipelines is owned by us and leased to Noble Petro as discussed below.
Abilene Terminal.
We own a terminal in Abilene, Texas that is leased to Noble Petro, Inc. ("Noble Petro") pursuant to a terminal and pipeline lease and operating agreement for nominal consideration. This terminal has nine operating tanks with an active aggregate shell capacity of approximately 368,000 barrels. Refined products for the Abilene terminal are supplied under our agreement with Noble Petro and are loaded on two loading lanes, each having three loading arms.
San Angelo Terminal.
We also own a terminal in San Angelo, Texas that is leased to Noble Petro under the same agreement as our Abilene terminal. This terminal has five tanks with an active aggregate shell capacity of approximately 93,000 barrels. Refined products for the San Angelo terminal are supplied under our agreement with Noble Petro and are loaded on two loading lanes, each having three loading arms.
50
The following table provides the location of the Abilene and San Angelo terminals associated with our marketing activities and their storage capacities, supply source, number of truck loading lanes, average truck loading volume and maximum daily available truck loading capacity for the years ended
December 31, 2013
and
2012
.
|
Maximum
|
|||||||||
|
Daily
|
|||||||||
|
Active
|
Available
|
||||||||
|
Aggregate
|
Number of
|
Truck
|
|||||||
|
Shell
|
Truck
|
Loading
|
|||||||
|
Number
|
Capacity
|
Supply
|
Loading
|
Capacity
|
|||||
|
Terminal Location
|
of Tanks
|
(bbls)
|
Source
|
Lanes
|
(bpd)
|
||||
|
Abilene, TX
(1)
|
9
|
|
368,000
|
|
Noble Petro
|
2
|
|
17,700
|
|
|
San Angelo, TX
|
5
|
|
93,000
|
|
Noble Petro
|
2
|
|
8,400
|
|
|
Total
|
14
|
|
461,000
|
|
4
|
|
26,100
|
|
|
|
(1)
|
Excludes approximately 86,000 barrels of shell capacity that is out of service and approximately 380,000 barrels of out of service shell capacity requiring extensive repair.
|
Abilene Area Terminals and Product Pipelines
51
Terminalling
We provide terminalling services for products to independent third parties and Delek’s retail segment through a light products terminal we own in Nashville, Tennessee and to J. Aron for products through a light products terminal in Memphis, Tennessee. See "Item 1—Business—Commercial Agreements—El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement" for a description of our agreement with J. Aron. We also own a light products terminal in Big Sandy, Texas, which is capable of providing terminalling and storage services to Delek's Tyler Refinery. The Big Sandy terminal was not operational for a majority of the year ended December 31, 2013. However, the terminal was available for use beginning in the fourth quarter of 2013.
Memphis Terminal.
Our Memphis terminal has 12 tanks (eight for gasoline and diesel and four for additives, ethanol, transmix and water) with an active aggregate shell capacity of approximately 114,000 barrels. We have an agreement with Delek, whereby Delek is able to directly supply our Memphis terminal with refined product from its El Dorado Refinery. Refined products are loaded on three fully-automated loading lanes. For a discussion of a third party's involvement in the terminalling agreement relative to our Memphis terminal, see "Item 1—Business—Commercial Agreements—El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement."
Nashville Terminal.
Our Nashville terminal has 10 tanks (seven for gasoline and diesel and three for additives, ethanol and water) with an active aggregate shell capacity of approximately 132,000 barrels. Although this terminal primarily provides terminalling and storage services for third parties, Delek has the ability to indirectly supply this terminal through product exchange agreements. Refined products are loaded on two loading lanes at this terminal.
Big Sandy Terminal.
The Big Sandy terminal has 13 storage tanks (four for gasoline and diesel and nine for additives and ethanol) with an active aggregate shell capacity of approximately 166,000 barrels. The Big Sandy terminal is supplied by the Tyler-Big Sandy Pipeline. The Big Sandy terminal was not operational for a majority of the year ended December 31, 2013 due to maintenance required on the Hopewell Pipeline portion of the Tyler-Big Sandy Pipeline. The terminal was available for use beginning in the fourth quarter of 2013, but no product was throughput at the terminal during this period.
Tyler Terminal.
Our Tyler Terminal consists of a truck loading rack with nine loading bays supplied by pipeline from 96 storage tanks located at the Tyler Refinery, along with certain ancillary assets.
North Little Rock Terminal.
Our North Little Rock terminal has five tanks (three for gasoline and diesel and two for additives and ethanol) with an active aggregate shell capacity of approximately 145,000 barrels. We have an agreement with Delek, whereby Delek is able to directly supply our North Little Rock terminal with refined product from its El Dorado Refinery. For a discussion of a third party's involvement in the terminalling agreement relative to our North Little Rock terminal, see "Item 1—Business—Commercial Agreements—El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement."
The following table provides the location of our refined product terminals associated with our terminalling activities and their storage capacities, supply source, number of truck loading lanes, average truck loading volume and maximum daily available truck loading capacity for the years ended
December 31, 2013
and
2012
.
|
Maximum
|
|||||||||
|
Daily
|
|||||||||
|
Active
|
Available
|
||||||||
|
Aggregate
|
Number of
|
Truck
|
|||||||
|
Shell
|
Truck
|
Loading
|
|||||||
|
Number
|
Capacity
|
Supply
|
Loading
|
Capacity
|
|||||
|
Terminal Location
|
of Tanks
|
(bbls)
|
Source
|
Lanes
|
(bpd)
|
||||
|
Big Sandy, TX
(1)
|
13
|
|
166,000
|
|
Tyler Refinery
|
3
|
|
25,000
|
|
|
Memphis, TN
(2)
|
12
|
|
114,000
|
|
Enterprise System/El Dorado Pipeline System
|
3
|
|
13,000
|
|
|
Nashville, TN
(3)
|
10
|
|
132,000
|
|
Pilot/MAPCO/Valero
|
2
|
|
8,900
|
|
|
Tyler, TX
(4)
|
Tyler Refinery
|
9
|
|
54,000
|
|
||||
|
North Little Rock, AR
|
5
|
|
145,000
|
|
El Dorado Refinery/Enterprise System
|
2
|
|
8,400
|
|
|
Total
|
40
|
|
557,000
|
|
19
|
|
109,300
|
|
|
52
|
(1)
|
The Big Sandy terminal was acquired by Delek on February 7, 2012 and was not operational for a majority of the year ended December 31, 2013 as a result of the Hopewell Pipeline being out of service. The terminal was available for use beginning in the fourth quarter 2013. For additional information, see "Big Sandy Terminal" above.
|
|
(2)
|
The Memphis Terminal supports the El Dorado Refinery.
|
|
(3)
|
In addition, we have approximately10,000 barrels of shell capacity that is currently not in service.
|
|
(4)
|
See "—Our Asset Portfolio—Pipelines and Transportation Segment—Tyler Tank Assets" above for a discussion of the storage tanks associated with this terminal.
|
Title to Properties and Permits
While we own the physical improvements consisting of our pipelines, substantially all of these pipelines are constructed on rights-of-way granted by the apparent record owners of the property and in some instances these rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines.
We believe that we are the owner of valid easement rights and rights-of-way or fee ownership or leasehold interests to the lands on which the above assets are located. Under the First Omnibus Amendment, Delek has agreed to indemnify us for certain title defects and for failures to obtain certain consents and permits necessary to conduct our business, in each case, that are identified prior to November 7, 2017, subject to a $250,000 aggregate annual deductible. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions, and other encumbrances to which the underlying properties were subject at the time of acquisition by our predecessor or us, we believe that none of these burdens should materially detract from the value of these properties or from our interest in these properties or should materially interfere with their use in the operation of our business.
Facilities
Our Nettleton Station and our Bradford Station are located on properties that are owned by Chevron and by a local family, respectively, in which we have leasehold interests. Our Tyler Terminal and Tank Farm is located on property that is owned by Delek in which we have a leasehold interest.
Liens and Encumbrances
The majority of the assets described above are pledged under and encumbered by our credit agreement. See Note 9 of the consolidated financial statements included in Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K for further information.
Corporate Headquarters
Delek leases its corporate headquarters at 7102 Commerce Way, Brentwood, Tennessee. The lease is for 54,000 square feet and expires in April 2022. We pay Delek a proportionate share of the costs to operate the building pursuant to the Second Restated Omnibus Agreement. Please read "Item 1—Business—Commercial Agreements—Other Agreements with Delek—Omnibus Agreement."
ITEM 3.
LEGAL PROCEEDINGS
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we do not believe that we are currently a party to any litigation that will have a material adverse impact on our financial condition, results of operations or cash flows. We are not currently aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
53
|
ITEM 5.
|
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
Unit Price and Cash Distributions
Our common units represent limited partner interests in us that entitle the holders to the rights and privileges specified in our partnership agreement. Our common units began trading on the NYSE under the symbol "DKL" on November 2, 2012. Prior to that time, there was no public market for our common units. There were three holders of record of our common units as of February 21, 2014, which includes common units held in street name. In addition, as of February 21, 2014, Delek and its subsidiaries owned
2,799,258
of our common units,
11,999,258
of our subordinated units and
492,893
of our general partner units (the 2% general partner interest), which together constitute a
60.0%
ownership interest in us.
The following table sets forth the range of the daily high and low sales prices per common unit and cash distributions to common unitholders for the period from November 1, 2012, the date our shares began trading.
|
Quarter Ended
|
High Sales Price
|
Low Sales Price
|
Quarterly Cash Distribution per Unit
(1)
|
Distribution Date
|
Record Date
|
|||||
|
December 31, 2013
|
$33.49
|
$29.51
|
$0.415
|
February 13, 2014
|
February 4, 2014
|
|||||
|
September 30, 2013
|
33.70
|
28.70
|
0.405
|
November 14, 2013
|
November 7, 2013
|
|||||
|
June 30, 2013
|
35.96
|
28.11
|
0.395
|
August 13, 2013
|
August 6, 2013
|
|||||
|
March 31, 2013
|
31.19
|
22.76
|
0.385
|
May 15, 2013
|
May 7, 2013
|
|||||
|
December 31, 2012 (from November 7, 2012)
|
$23.74
|
$20.52
|
$0.224
|
February 14, 2013
|
February 6, 2013
|
|||||
|
(1)
|
Represents cash distributions attributable to the quarter and declared and paid within 45 days of quarter end in accordance with our partnership agreement. The distribution for the quarter ended December 31, 2012 reflects the pro rata portion of the minimum quarterly distribution rate of
$0.375
for the period beginning November 7, 2012, the date the Partnership commenced operations.
|
Distributions of Available Cash
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.
Definition of Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
|
•
|
less
the amount of cash reserves established by our general partner to:
|
|
◦
|
provide for the proper conduct of our business (including cash reserves for our future capital expenditures and anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);
|
|
◦
|
comply with applicable law, any of our debt instruments or other agreements; or
|
|
◦
|
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
|
54
|
•
|
plus
, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings.
|
Intent to Distribute the Minimum Quarterly Distribution
We intend to pay a quarterly distribution of at least
$0.375
per unit per quarter, or
$1.50
per unit on an annualized basis, which equals approximately
$9.2 million
per quarter, or approximately
$37.0 million
per year, based on the number of common, subordinated and general partner units outstanding as of
December 31, 2013
. We do not have a legal obligation to pay this distribution.
General Partner Interest and Incentive Distribution Rights
Our general partner is currently entitled to 2.0% of all quarterly distributions that we make prior to our liquidation. This general partner interest is represented by
492,893
general partner units. Our general partner has the right, but not the obligation, to contribute up to a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s 2.0% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.
Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48.0%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of $0.43125 per unit per quarter. The maximum distribution of 48.0% does not include any distributions that our general partner or its affiliates may receive on common, subordinated or general partner units that it owns.
Percentage Allocations of Available Cash
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.
|
Total Quarterly
|
Marginal Percentage
|
|||||||
|
Distribution per Unit
|
Interest in Distributions
|
|||||||
|
Target Amount
|
Unitholders
|
General Partner
|
||||||
|
Minimum Quarterly Distribution
|
$0.37500
|
98.0
|
%
|
2.0
|
%
|
|||
|
First Target Distribution
|
above $0.37500
|
98.0
|
%
|
2.0
|
%
|
|||
|
up to $0.43125
|
||||||||
|
Second Target Distribution
|
above $0.43125
|
85.0
|
%
|
15.0
|
%
|
|||
|
up to $0.46875
|
||||||||
|
Third Target Distribution
|
above $0.46875
|
75.0
|
%
|
25.0
|
%
|
|||
|
up to $0.56250
|
||||||||
|
Thereafter
|
above $0.56250
|
50.0
|
%
|
50.0
|
%
|
|||
Subordination Period
General
Our partnership agreement provides that, during the subordination period (which we define below), our common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.375 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any
55
arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.
Subordination Period
Except as described below, the subordination period will extend until the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending December 31, 2015, that each of the following tests are met:
|
•
|
distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $1.50 per unit (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
|
|
•
|
the adjusted operating surplus (as defined in our partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $1.50 (the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and
|
|
•
|
there are no arrearages in payment of the minimum quarterly distribution on the common units.
|
In addition to the tests outlined above, the subordination period will end only in the event that our conflicts committee, or the board of directors of our general partner based on the recommendation of our conflicts committee, reasonably expects to satisfy the tests set forth under the first and second bullet points above for the succeeding four-quarter period without treating as earned any shortfall payments that would be paid under our existing commercial agreements with Delek (or similar fees to be paid by Delek under future contracts) expected to be received during such period.
Early Termination of Subordination Period
Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending December 31, 2013, that each of the following tests are met:
|
•
|
distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $2.25 (150% of the annualized minimum quarterly distribution), for the four-consecutive-quarter period immediately preceding that date;
|
|
•
|
the adjusted operating surplus generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $2.25 per unit (150% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and
|
|
•
|
there are no arrearages in payment of the minimum quarterly distributions on the common units.
|
In addition to the tests outlined above, the subordination period will end only in the event that our conflicts committee, or the board of directors of our general partner based on the recommendation of our conflicts committee, reasonably expects to satisfy the tests set forth under the first and second bullet points above for the succeeding four-quarter period without treating as earned any shortfall payments that would be paid under our existing commercial agreements with Delek (or similar fees to be paid by Delek under future contracts) expected to be received during such period.
Expiration Upon Removal of the General Partner
In addition, if the unitholders remove our general partner other than for cause:
|
•
|
the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner;
|
|
•
|
if all of the subordinated units convert pursuant to the foregoing, all cumulative arrearages on the common units will be extinguished and the subordination period will end; and
|
56
|
•
|
our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.
|
Expiration of the Subordination Period
When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.
Performance Graph
The following Performance Graph and related information shall not be deemed
“
soliciting material” or to be “filed” with the Securities and Exchange Commission,
nor shall such information be incorporated by reference into any future filing under
the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended,
except to the extent that Delek Logistics Partners, LP (the "Partnership" or "DKL") specifically incorporates it by reference into such filing.
The performance graph below matches the cumulative total return of our common units with the cumulative total return of the Standard and Poor's 500 Composite Index and a customized peer group of nine companies that includes: Enbridge Energy Partners, L.P. (NYSE: EEP), Holly Energy Partners, L.P. (NYSE: HEP), Magellan Midstream Partners, L.P. (NYSE: MMP), MPLX LP (NYSE: MPLX), NuSTAR Energy LP (NYSE: NS), Plains All American Pipeline, L.P., (NYSE: PAA), Sunoco Logistics Partners, L.P. (NYSE: SXL), Tesoro Logistics LP (NYSE: TLLP) and Transmontaigne Partners, L.P. (NYSE: TLP). The unit performance shown on the graph below is not necessarily indicative of future price performance.
The Peer Group was selected by the Partnership and contains logistics companies we believe to follow a similar business model to DKL's, including crude oil gathering and refined products terminalling, transportation and storage. The graph below is for the period commencing November 2, 2012, our first day of trading on the NYSE, and ending
December 31, 2013
. The graph assumes that the value of the investment in our common stock, in each index, and in the peer group (including reinvestment of dividends) was $100.
57
COMPARISON OF CUMULATIVE TOTAL RETURN
ITEM 6.
SELECTED FINANCIAL DATA
The following tables set forth certain selected consolidated financial data as of and for each of the five years in the period ended
December 31, 2013
. The selected historical consolidated financial data for the years ended
December 31, 2012
,
2011
,
2010
and
2009
are derived from audited consolidated financial statements of the DKL Predecessor. The selected historical financial data for the 2012 period presented through November 6, 2012 is derived from consolidated financial results of the DKL Predecessor, and the period beginning November 7, 2012 is derived from consolidated financial results of Delek Logistics Partners, LP. The selected historical consolidated financial data for the year ended December 31, 2013 is derived from consolidated financial results of Delek Logistics Partners, LP. The following tables should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and our consolidated financial statements in Item 8.
On July 26, 2013, we completed the Tyler Acquisition to acquire from Delek the Tyler Terminal and Tank Assets. The Tyler Acquisition was a transfer between entities under common control. Accordingly, the financial information contained herein of the DKL Predecessor and the Partnership has been retrospectively adjusted to include the historical results of the Tyler Predecessor for all periods presented through July 26, 2013.
58
Our financial information includes the historical results of our Predecessors (for all periods presented) and the results of the Partnership beginning November 7, 2012, the date we commenced operations. Our financial results may not be comparable as our Predecessors recorded revenues, general and administrative expenses and financed operations differently than the Partnership. See "Factors Affecting the Comparability of Our Financial Results" in Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 for additional information.
59
|
Year Ended December 31,
|
||||||||||||||||||||
|
2013
(4)
|
2012
(4)
|
2011
(3)(4)
|
2010
(4)
|
2009
(1)(2)(4)
|
||||||||||||||||
|
Predecessors
|
Predecessors
|
Predecessors
|
Predecessors
|
|||||||||||||||||
|
Statement of Operations Data:
|
(In thousands, except units and per unit data)
|
|||||||||||||||||||
|
Net sales:
|
|
|
|
|
|
|||||||||||||||
|
Pipelines and Transportation
|
$
|
60,237
|
|
$
|
33,539
|
|
$
|
21,878
|
|
$
|
9,451
|
|
$
|
6,633
|
|
|||||
|
Wholesale Marketing and Terminalling
|
847,191
|
|
989,047
|
|
722,201
|
|
494,957
|
|
367,787
|
|
||||||||||
|
Total net sales
|
907,428
|
|
1,022,586
|
|
|
744,079
|
|
|
504,408
|
|
|
374,420
|
|
|||||||
|
Operating costs and expenses:
|
|
|
|
|
|
|||||||||||||||
|
Cost of goods sold
|
811,364
|
|
959,434
|
|
700,505
|
|
476,678
|
|
349,493
|
|
||||||||||
|
Operating expenses
|
30,302
|
|
30,397
|
|
19,467
|
|
5,905
|
|
8,971
|
|
||||||||||
|
General and administrative expenses
|
6,856
|
|
9,150
|
|
6,483
|
|
5,010
|
|
6,889
|
|
||||||||||
|
Depreciation and amortization
|
12,436
|
|
10,120
|
|
6,061
|
|
3,825
|
|
3,702
|
|
||||||||||
|
Loss (gain) on sale of assets
|
166
|
|
9
|
|
(2
|
)
|
—
|
|
—
|
|
||||||||||
|
Total operating costs and expenses
|
861,124
|
|
1,009,110
|
|
732,514
|
|
|
491,418
|
|
|
369,055
|
|
||||||||
|
Operating income
|
46,304
|
|
13,476
|
|
11,565
|
|
|
12,990
|
|
|
5,365
|
|
||||||||
|
Interest expense, net
|
4,570
|
|
2,682
|
|
2,011
|
|
2,564
|
|
2,173
|
|
||||||||||
|
Income before income tax (benefit) expense
|
41,734
|
|
10,794
|
|
9,554
|
|
10,426
|
|
3,192
|
|
||||||||||
|
Income tax expense (benefit)
|
757
|
|
(14,024
|
)
|
5,363
|
|
5,102
|
|
4,059
|
|
||||||||||
|
Net income (loss)
|
|
$
|
40,977
|
|
$
|
24,818
|
|
$
|
4,191
|
|
$
|
5,324
|
|
$
|
(867
|
)
|
||||
|
Less: (Loss) income attributable to Predecessors
|
(6,853
|
)
|
16,408
|
|
4,191
|
|
$
|
—
|
|
$
|
—
|
|
||||||||
|
Net income (loss) attributable to partners
|
$
|
47,830
|
|
$
|
8,410
|
|
$
|
—
|
|
$
|
5,324
|
|
$
|
(867
|
)
|
|||||
|
Comprehensive income (loss) attributable to partners
|
|
$
|
47,830
|
|
$
|
8,410
|
|
|
$
|
—
|
|
|
$
|
5,324
|
|
|
$
|
(867
|
)
|
|
|
Less: General partners' interest in net income (2%)
|
|
$
|
957
|
|
168
|
|
||||||||||||||
|
Limited partners' interest in net income
|
|
$
|
46,873
|
|
$
|
8,242
|
|
|||||||||||||
|
Net income per limited partner unit:
|
||||||||||||||||||||
|
Common - (basic)
|
|
$
|
1.95
|
|
$
|
0.34
|
|
|||||||||||||
|
Common - (diluted)
|
$
|
1.93
|
|
$
|
0.34
|
|
||||||||||||||
|
Subordinated - Delek (basic and diluted)
|
$
|
1.95
|
|
$
|
0.34
|
|
||||||||||||||
|
Weighted average limited partner units outstanding:
|
|
|
|
|
||||||||||||||||
|
Common units - (basic)
|
12,025,249
|
|
11,999,258
|
|
||||||||||||||||
|
Common units - (diluted)
|
12,148,774
|
|
11,999,258
|
|
||||||||||||||||
|
Subordinated units - Delek (basic and diluted)
|
11,999,258
|
|
11,999,258
|
|
||||||||||||||||
|
(1)
|
The Tyler Refinery did not operate during the period from November 21, 2008 through May 17, 2009 due to an explosion and fire on November 20, 2008. The Tyler Refinery resumed full operations on May 18, 2009. During the period for which the Tyler Refinery was not in operation, Delek continued to pay us amounts consistent with historical averages despite the absence of operations at portions of our business.
|
60
|
(2)
|
Financial
information and operating information for the East Texas Crude Logistics System for the year ended December 31, 2009 is for the 275 days that we operated the system and includes payments related to minimum volume commitments in April and May 2009 as a result of reduced volumes prior to the resumption of operations at the Tyler Refinery in May 2009.
|
|
(3)
|
Financial
information and operating information (other than information relating to operations in east and west Texas) for the year ended December 31, 2011 is for the 247 days and 12 days Delek operated the El Dorado Refinery and Paline Pipeline System, respectively, in 2011.
|
|
(4)
|
The information presented includes the results of operations of our Predecessors. Prior to the completion of the Offering and the Tyler Acquisition, our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services.
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
2009
|
|||||||||||
|
Predecessors
|
Predecessors
|
Predecessors
|
Predecessors
|
|||||||||||||||||
|
Cash Flow Data:
|
|
(In thousands)
|
||||||||||||||||||
|
Cash flows provided by (used in) operating activities
|
|
$
|
44,391
|
|
$
|
26,612
|
|
$
|
(10,052
|
)
|
$
|
9,796
|
|
$
|
(1,498
|
)
|
||||
|
Cash flows used in investing activities
|
|
(20,135
|
)
|
(50,010
|
)
|
(7,130
|
)
|
(6,721
|
)
|
(2,994
|
)
|
|||||||||
|
Cash flows (used in) provided by financing activities
|
|
(46,784
|
)
|
46,815
|
|
17,217
|
|
(3,154
|
)
|
3,894
|
|
|||||||||
|
Net (decrease) increase in cash and cash equivalents
|
|
$
|
(22,528
|
)
|
$
|
23,417
|
|
$
|
35
|
|
$
|
(79
|
)
|
$
|
(598
|
)
|
||||
|
Year Ended December 31,
|
||||||||||||||||||||
|
|
2013
|
2012
|
2011
|
2010
|
2009
|
|||||||||||||||
|
Predecessors
|
Predecessors
|
Predecessors
|
Predecessors
|
|||||||||||||||||
|
Balance Sheet Data:
|
(In thousands)
|
|||||||||||||||||||
|
Property, plant and equipment, net
|
$
|
199,282
|
|
$
|
191,057
|
|
$
|
157,012
|
|
$
|
46,262
|
|
$
|
42,304
|
|
|||||
|
Total assets
|
274,804
|
|
283,316
|
|
223,159
|
|
90,159
|
|
77,719
|
|
||||||||||
|
Total debt, including current maturities
|
164,800
|
|
90,000
|
|
30,300
|
|
29,000
|
|
42,500
|
|
||||||||||
|
Total liabilities
|
212,763
|
|
143,301
|
|
94,297
|
|
61,516
|
|
64,832
|
|
||||||||||
|
Total equity
|
62,041
|
|
140,015
|
|
129,142
|
|
28,643
|
|
12,887
|
|
||||||||||
61
Segment Data
(1)
:
|
|
As of and For the Year Ended December 31, 2013
(2)
|
|||||||||||
|
(In thousands)
|
Pipelines and Transportation
|
Wholesale Marketing and Terminalling
|
Consolidated
|
|||||||||
|
Net sales
|
$
|
60,237
|
|
$
|
847,191
|
|
$
|
907,428
|
|
|||
|
Operating costs and expenses:
|
|
|
|
|||||||||
|
Cost of goods sold
|
764
|
|
810,600
|
|
811,364
|
|
||||||
|
Operating expenses
|
22,903
|
|
7,399
|
|
30,302
|
|
||||||
|
Segment contribution margin
|
36,570
|
|
29,192
|
|
65,762
|
|
||||||
|
General and administrative expenses
|
|
|
6,856
|
|
||||||||
|
Depreciation and amortization
|
|
|
12,436
|
|
||||||||
|
Loss on sale of assets
|
|
|
166
|
|
||||||||
|
Operating income
|
|
|
$
|
46,304
|
|
|||||||
|
Total assets
|
$
|
164,608
|
|
$
|
110,196
|
|
$
|
274,804
|
|
|||
|
Capital spending (excluding business combinations)
(3)
|
$
|
6,905
|
|
$
|
2,493
|
|
$
|
9,398
|
|
|||
|
(1)
|
Accounting Standards Codification (“ASC”) 280,
Segment
Reporting
, requires disclosure of a measure of segment profit or loss. We measure the operating performance of each segment based on segment contribution margin. We define segment contribution margin as net sales less cost of goods sold and operating expenses, excluding depreciation and amortization.
|
For the pipelines and transportation segment, operating expenses include the costs associated with the actual operation of owned pipelines, excluding depreciation and amortization.
For the wholesale marketing and terminalling segment, cost of goods sold includes all costs of refined products, additives and related transportation. Operating expenses include the costs associated with the actual operation of owned terminals, excluding depreciation and amortization.
|
(2)
|
The
information presented includes the results of operations of the Tyler Predecessor. Prior to the Tyler Acquisition, the Tyler Predecessor did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services.
|
|
(3)
|
Capital spending includes expenditures incurred in connection with the assets acquired in the Tyler Acquisition.
|
62
|
|
As of and For the Year Ended December 31, 2012
(4)
|
|||||||||||
|
Predecessors
|
||||||||||||
|
(In thousands)
|
Pipelines and Transportation
|
Wholesale Marketing and Terminalling
|
Consolidated
|
|||||||||
|
Net sales
|
$
|
33,539
|
|
$
|
989,047
|
|
$
|
1,022,586
|
|
|||
|
Operating costs and expenses:
|
|
|
|
|||||||||
|
Cost of goods sold
|
—
|
|
959,434
|
|
959,434
|
|
||||||
|
Operating expenses
|
24,155
|
|
6,242
|
|
30,397
|
|
||||||
|
Segment contribution margin
|
9,384
|
|
23,371
|
|
32,755
|
|
||||||
|
General and administrative expenses
|
|
|
9,150
|
|
||||||||
|
Depreciation and amortization
|
|
|
10,120
|
|
||||||||
|
Loss on sale of assets
|
|
|
9
|
|
||||||||
|
Operating income
|
|
|
$
|
13,476
|
|
|||||||
|
Total assets
|
$
|
183,204
|
|
$
|
100,112
|
|
$
|
283,316
|
|
|||
|
Capital spending (excluding business combinations)
(5)
|
$
|
22,146
|
|
$
|
4,613
|
|
$
|
26,759
|
|
|||
|
(4)
|
The information presented includes the results of operations of our Predecessors. Prior to the completion of the Offering and the Tyler Acquisition, our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services.
|
|
(5)
|
Capital spending includes expenditures incurred in connection with the assets acquired in the Tyler Acquisition.
|
|
|
As of and For the Year Ended December 31, 2011
(6)(7)
|
|||||||||||
|
Predecessors
|
||||||||||||
|
(In thousands)
|
Pipelines and Transportation
|
Wholesale Marketing and Terminalling
|
Consolidated
|
|||||||||
|
Net sales
|
$
|
21,878
|
|
$
|
722,201
|
|
$
|
744,079
|
|
|||
|
Operating costs and expenses:
|
|
|
|
|||||||||
|
Cost of goods sold
|
—
|
|
700,505
|
|
700,505
|
|
||||||
|
Operating expenses
|
15,415
|
|
4,052
|
|
19,467
|
|
||||||
|
Segment contribution margin
|
6,463
|
|
17,644
|
|
24,107
|
|
||||||
|
General and administrative expenses
|
|
|
6,483
|
|
||||||||
|
Depreciation and amortization
|
|
|
6,061
|
|
||||||||
|
Gain on sale of assets
|
(2
|
)
|
||||||||||
|
Operating income
|
|
|
$
|
11,565
|
|
|||||||
|
Total assets
|
$
|
133,257
|
|
$
|
89,902
|
|
$
|
223,159
|
|
|||
|
Capital spending (excluding business combinations)
(8)
|
$
|
5,905
|
|
$
|
1,225
|
|
$
|
7,130
|
|
|||
63
|
(6)
|
The
information presented includes the results of operations of our Predecessors. Prior to the completion of the Offering and the Tyler Acquisition, our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services.
|
|
(7)
|
In April 2011, Delek completed the acquisition of a controlling interest in Lion Oil. Certain assets of Lion Oil were transferred to us in connection with the Offering. The operating results of the Lion Oil contributed assets are included in the pipelines and transportation segment and the wholesale marketing and terminalling segment for the 247 days Delek operated the El Dorado Refinery in 2011.
|
|
(8)
|
Capital
spending includes expenditures incurred in connection with the assets acquired in the Tyler Acquisition.
|
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Unless the context otherwise requires, references in this report to "Delek Logistics Partners, LP Predecessor," the "Predecessor," and "we," "our," "us" or like terms, when used in the context of periods prior to November 7, 2012, refer to Delek Logistics Partners, LP Predecessor, the Partnership's predecessor for accounting purposes. References to "Delek Logistics Partners, LP," the "Partnership," and "we," "our," "us," or like terms, when used in the present tense or in the context of periods on or after November 7, 2012, refer to Delek Logistics Partners, LP and its general partner and subsidiaries. Unless the context otherwise requires, references in this report to "Delek" refer collectively to Delek US Holdings, Inc. and any of its subsidiaries, other than Delek Logistics Partners, LP, its subsidiaries and its general partner. Those statements in this section that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See "Forward-Looking Statements" below for a discussion of the factors that could cause actual results to differ materially from those projected in these statements.
You should read the following discussion of our financial condition and results of operations in conjunction with our historical consolidated financial statements and notes thereto.
Forward-Looking Statements
This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking statements reflect our current estimates, expectations and projections about our future results, performance, prospects and opportunities. Forward-looking statements include, among other things, the information concerning our possible future results of operations, business and growth strategies, financing plans, expectations that regulatory developments or other matters will not have a material adverse effect on our business or financial condition, our competitive position and the effects of competition, the projected growth of the industry in which we operate, and the benefits and synergies to be obtained from our completed and any future acquisitions, and statements of management’s goals and objectives, and other similar expressions concerning matters that are not historical facts. Words such as “may,” “will,” “should,” “could,” “would,” “predicts,” “potential,” “continue,” “expects,” “anticipates,” “future,” “intends,” “plans,” “believes,” “estimates,” “appears,” “projects” and similar expressions, as well as statements in future tense, identify forward-looking statements.
Forward-looking statements should not be read as a guarantee of future performance or results, and will not necessarily be accurate indications of the times at, or by, which such performance or results will be achieved. Forward-looking information is based on information available at the time and/or management’s good faith belief with respect to future events, and is subject to risks and uncertainties that could cause actual performance or results to differ materially from those expressed in the statements. Important factors that, individually or in the aggregate, could cause such differences include, but are not limited to:
|
•
|
our substantial dependence on Delek or its assignees and its ability to pay us under our commercial agreements;
|
|
•
|
operating hazards and other risks incidental to transporting, storing and gathering crude oil and refined products;
|
|
•
|
the timing and extent of changes in commodity prices and demand for Delek’s refined products;
|
|
•
|
the suspension, reduction or termination of Delek's or its assignees' or any third-party's obligations under our commercial agreements;
|
64
|
•
|
disruptions due to acts of God, equipment interruption or failure at our facilities, Delek’s facilities or third-party facilities on which our business is dependent;
|
|
•
|
changes in general economic conditions;
|
|
•
|
competitive conditions in our industry;
|
|
•
|
actions taken by our customers and competitors;
|
|
•
|
the demand for crude oil, refined products and transportation and storage services;
|
|
•
|
our ability to successfully implement our business plan;
|
|
•
|
our ability to complete internal growth projects on time and on budget;
|
|
•
|
Delek's inability to grow as expected;
|
|
•
|
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
|
|
•
|
interest rates;
|
|
•
|
labor relations;
|
|
•
|
large customer defaults;
|
|
•
|
changes in the availability and cost of capital and the price or availability of debt and equity financing;
|
|
•
|
changes in tax status;
|
|
•
|
the effects of existing and future laws and governmental regulations, including but not limited to the rules and regulations promulgated by the FERC;
|
|
•
|
changes in insurance markets impacting costs and the level and types of coverage available;
|
|
•
|
the effects of future litigation; and
|
|
•
|
other factors discussed elsewhere in this report.
|
In light of these risks, uncertainties and assumptions, our actual results of operations and execution of our business strategy could differ materially from those expressed in, or implied by, the forward-looking statements, and you should not place undue reliance upon them. In addition, past financial and/or operating performance is not necessarily a reliable indicator of future performance and you should not use our historical performance to anticipate results or future period trends. We can give no assurances that any of the events anticipated by the forward-looking statements will occur or, if any of them do, what impact they will have on our results of operations and financial condition.
Forward-looking statements speak only as of the date the statements are made. We assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking information except to the extent required by applicable securities laws. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect thereto or with respect to other forward-looking statements.
Business Overview
The Partnership primarily owns and operates crude oil and intermediate and refined products logistics and marketing assets. We gather, transport and store crude oil and market, distribute, transport and store refined products in select regions of the southeastern United States and Texas for Delek and third parties, primarily in support of Delek’s Tyler and El Dorado Refineries. A substantial majority of our existing assets are both integral to and dependent upon the success of Delek’s refining operations as our assets are contracted exclusively to Delek in support of its Tyler and El Dorado Refineries.
The Partnership is not a taxable entity for federal income tax purposes or the income taxes of those states that follow the federal income tax treatment of partnerships. Instead, for purposes of these income taxes, each partner of the Partnership is required to take into account its share of items of income, gain, loss and deduction in computing its federal and state income tax liabilities, regardless of whether cash distributions are made to the partner by the partnership. The taxable income reportable to each partner takes into account differences between the tax basis and the fair market value of our assets and financial reporting bases of assets and liabilities, the acquisition price of their units and the taxable income allocation requirements under the partnership agreement.
65
Recent Developments
El Dorado Terminal and Tankage Acquisition
On February 10, 2014, the Partnership and OpCo completed a transaction with Lion Oil, pursuant to which OpCo acquired a refined products terminal, storage tanks and ancillary assets on and adjacent to the El Dorado Refinery. The purchase price paid for the assets acquired was $95.9 million in cash financed with borrowings under the Partnership's amended and restated senior secured revolving credit facility. In addition, the parties entered into several contracts and amended certain existing contracts in connection with the El Dorado Transaction. The assets acquired in the El Dorado Transaction consist of:
|
•
|
The El Dorado Terminal, which consists of a truck loading rack with three loading bays supplied by pipeline from storage tanks located at the El Dorado Refinery, along with certain ancillary assets. Total throughput capacity for the El Dorado Terminal is approximately 26,700 bpd. For the year ended December 31, 2012, approximately 12,649 bpd of refined products were throughput at the El Dorado Terminal.
|
|
•
|
The El Dorado Storage Tanks, which consist of 158 storage tanks and certain ancillary assets (such as pumps and piping) located adjacent to and at the El Dorado Refinery with an aggregate shell capacity of approximately 2.5 million barrels.
|
In connection with the El Dorado Transaction, the Partnership entered into and amended, as applicable, the following definitive agreements:
El Dorado Throughput and Tankage Agreement
. On February 10, 2014, in connection with the El Dorado Transaction, Lion Oil and OpCo, and for limited purposes, J. Aron & Company ("J. Aron"), entered into the El Dorado Throughput and Tankage Agreement. Under the El Dorado Throughput and Tankage Agreement, OpCo will provide Lion Oil with throughput and storage services in return for throughput and storage fees. The initial term of the El Dorado Throughput and Tankage Agreement is eight years and Lion Oil, at its sole option, may extend the term for two renewal terms of four years each. Effective February 10, 2014, Lion Oil assigned J. Aron its rights to use and transport materials through the El Dorado Terminal and Tank Assets until the expiration of Lion Oil’s amended and restated supply and offtake agreement with J. Aron. Despite the assignment Lion Oil still retains certain rights and obligations under the Throughput and Tankage Agreement.
Second Omnibus Amendment
. On February 10, 2014, in connection with the El Dorado Transaction, the Partnership entered into the Second Omnibus Amendment with our general partner, OpCo, certain of the Partnership’s other subsidiaries, Delek, Lion Oil and Delek Refining, Ltd., a wholly owned subsidiary of Delek. The Second Omnibus Amendment includes the following, among other things: (i) certain modifications in the reimbursement amounts to be paid by Delek and certain of its subsidiaries under the Omnibus Agreement for certain operating expenses and capital expenditures incurred by the Partnership or its subsidiaries; (ii) certain modifications of the indemnification provisions under the Omnibus Agreement in favor of the Partnership with respect to certain environmental matters; and (iii) the increase of the annual administrative fee payable by the Partnership to Delek under the Omnibus Agreement for corporate general and administrative services from $3.0 million to $3.3 million, which is prorated and payable monthly.
El Dorado Lease and Access Agreement
. On February 10, 2014, in connection with the El Dorado Transaction, Lion Oil and OpCo entered into the El Dorado Lease. Under the El Dorado Lease, OpCo leases from Lion Oil the real property on which the El Dorado Terminal and Tank Assets are located. The El Dorado Lease has an initial term of 50 years with automatic renewal for a maximum of four successive 10-year periods thereafter.
El Dorado Site Services Agreement
. On February 10, 2014, in connection with the El Dorado Transaction, Lion Oil and OpCo entered into the El Dorado Site Services Agreement. Under the El Dorado Site Services Agreement, Lion Oil provides OpCo with shared use of certain services, materials and facilities that are necessary to operate and maintain the El Dorado Terminal and Tank Assets as currently operated and maintained. The term of the El Dorado Site Services Agreement is co-terminous with the El Dorado Lease discussed above.
66
2013 Developments
Acquisitions
North Little Rock Terminal
. On October 24, 2013, we purchased the North Little Rock Terminal from Enterprise Refined Products Company LLC. The aggregate purchase price was approximately $5.0 million, which has been preliminarily allocated to property, plant and equipment and intangible assets. The valuation is subject to change during the purchase price allocation period.
Tyler Terminal and Tank Assets
. On July 26, 2013, the Partnership completed the acquisition of the Tyler Terminal and the Tyler Tank Assets. The purchase price paid for the assets acquired was $94.8 million in cash.
Hopewell Pipeline.
On July 19, 2013, the Partnership purchased the Hopewell Pipeline, which originates at the Tyler Refinery and terminates at the Hopewell Station, where it effectively connects to the Big Sandy Pipeline. The Hopewell Pipeline and the Big Sandy Pipeline form essentially one pipeline link between the Tyler Refinery and the Big Sandy Terminal. The aggregate purchase price for the Hopewell Pipeline was approximately $5.7 million, which has been preliminarily allocated to property, plant and equipment. The property, plant and equipment valuation is subject to change during the purchase price allocation period.
Other Developments
Amended and Restated Credit Facility
. On July 9, 2013, we entered into the Amended and Restated Credit Agreement, which amended and restated our senior secured revolving credit agreement, which we originally entered into on November 7, 2012, with Fifth Third Bank, as administrative agent, and a syndicate of lenders. Under the terms of the Amended and Restated Credit Agreement, the lender commitments were increased from $175.0 million to $400.0 million and a dual currency borrowing tranche was added that permits draw downs in U.S. or Canadian dollars. The Amended and Restated Credit Agreement also contains an accordion feature whereby the Partnership can increase the size of the credit facility to an aggregate of $450.0 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent.
Borrowings denominated in U.S. dollars under the Amended and Restated Credit Agreement bear interest at either a U.S. dollar prime rate, plus an applicable margin, or LIBOR, plus an applicable margin, at the election of the borrowers. Borrowings denominated in Canadian dollars under the Amended and Restated Credit Agreement bear interest at either a Canadian dollar prime rate, plus an applicable margin, or CDOR, plus an applicable margin, at the election of the borrowers. The applicable margin in each case varies based upon the Partnership's most recently reported leverage ratio.
Macedonia Crude Oil Release
. On October 7, 2013, a release of crude oil was identified from a gathering line near Macedonia, Arkansas. Approximately 40 barrels of crude oil were recovered from an adjacent small creek. Other than maintaining booms on a portion of the creek, cleanup operations for the creek were essentially concluded in November 2013; however, remediation of impacted soils along the pipeline remains to be completed. Based on current information available to us, we do not believe the total costs associated with this event, including any fines or penalties and net of partial insurance reimbursement, will have a material adverse effect upon our business, financial condition or results of operations.
Magnolia Station Crude Oil Release.
On March 9, 2013, a release of crude oil was detected within a pumping facility at our Magnolia Station located west of the El Dorado Refinery. The pumping facility is owned by our subsidiary SALA Gathering Systems, LLC. Since detecting the release we have worked to contain the release, recover the released crude oil and remediate those areas impacted by the release, coordinating our efforts with the EPA and state authorities to restore the impacted area to the satisfaction of the appropriate regulatory authorities. As of the date of this filing, we believe we have substantially completed all necessary remediation, restoration and monitoring of the areas affected by the crude oil release, although there are on-going discussions with ADEQ regarding whether additional monitoring or remediation of soil may be necessary. The release did not impact the delivery of crude oil from the Magnolia Station to the El Dorado Refinery and did not interrupt the operations of the El Dorado Pipeline connected to the Magnolia Station.
Business Strategies
Our objectives are to maintain stable cash flows and to grow the quarterly distributions paid to our unitholders. We intend to achieve these objectives through the following business strategies:
|
•
|
Generate Stable Cash Flow.
We will continue to pursue opportunities to provide logistics, marketing and other services to Delek and third parties pursuant to long-term, fee-based contracts. In new service contracts, we will
|
67
endeavor to negotiate minimum throughput or other commitments similar to those included in our current commercial agreements with Delek.
|
•
|
Focus on Growing Our Business.
We intend to evaluate and pursue opportunities to grow our business through both strategic acquisitions and organic expansion projects. We believe that our strong relationship with our sponsor will provide us with several opportunities to grow our business.
|
|
◦
|
Pursue Acquisitions
.
We plan to pursue strategic acquisitions that both complement our existing assets and provide attractive returns for our unitholders. For example, in February 2014, we completed the purchase of the El Dorado Terminal and Tank Assets. Additionally, Delek has granted us a right of first offer on certain other logistics assets that were not transferred to us as part of the Offering. Delek is also required, under certain circumstances, to offer us the opportunity to purchase additional logistics assets that Delek may acquire or construct in the future. Furthermore, we believe that our current asset base and our knowledge of the regional markets in which we operate will allow us to target and consummate attractive third-party acquisitions.
|
|
◦
|
Pursue Attractive Organic Expansion and Construction Opportunities.
We intend to pursue organic growth opportunities that complement our existing businesses or that provide attractive returns within or outside our current geographic footprint. We plan to evaluate any potential opportunities to make capital investments that will be used to expand our existing asset base through the development and construction of new logistics assets for which a need may arise as a result of the growth of any of our customers', including Delek's, businesses or from increased third-party activity.
|
|
•
|
Optimize Our Existing Assets and Expand Our Customer Base.
We intend to enhance the profitability of our existing assets by adding incremental throughput volumes, improving operating efficiencies and increasing system-wide utilization. For example, we have announced plans to increase the throughput capacity and diversify our product mix at the North Little Rock Terminal by completing certain capital projects that will expand the terminal and enhance its operational capabilities. Additionally, we are considering options to optimize the economics of the Paline Pipeline System over the next few years, including but not limited to, extending the contract with our current customer on terms beneficial to both parties. We also expect to further diversify our customer base by increasing third-party throughput volumes running through certain of our existing systems and expanding our existing asset portfolio to service more third-party customers.
|
Commercial Agreements
The Partnership has various long-term, fee-based commercial agreements with Delek under which we provide crude oil gathering, crude oil and refined products transportation and storage services and marketing and terminalling services to Delek, and Delek commits to provide us with minimum monthly throughput volumes of crude oil and refined products. For a description of each agreement, see "Item 1—Business—Commercial Agreements—Commercial Agreements in Connection with the Offering" and "Item 1—Business—Commercial Agreements—Commercial Agreements in Connection with the Tyler Acquisition".
How We Evaluate Our Operations
We use a variety of financial and operating metrics to analyze our segment performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) volumes (including pipeline throughput and terminal volumes); (ii) contribution margin and gross margin per barrel; (iii) operating and maintenance expenses; and (iv) EBITDA and Distributable Cash Flow (as such terms are defined below).
Volumes
. The amount of revenue we generate primarily depends on the volumes of crude oil and intermediate and refined products that we handle in our pipeline, transportation, terminalling and marketing operations. These volumes are primarily affected by the supply of and demand for crude oil and refined products in the markets served directly or indirectly by our assets. Although Delek has committed to minimum volumes under the commercial agreements described above, our results of operations will be impacted by:
68
|
•
|
Delek’s utilization of our assets in excess of its minimum volume commitments;
|
|
•
|
our ability to identify and execute acquisitions and organic expansion projects, and capture incremental volume increases from Delek or third-parties;
|
|
•
|
our ability to increase throughput volumes at our refined products terminals and provide additional ancillary services at those terminals, such as ethanol blending and additive injection;
|
|
•
|
our ability to identify and serve new customers in our marketing operations; and
|
|
•
|
our ability to make connections to third-party facilities and pipelines.
|
Contribution Margin and Gross Margin per Barrel.
Because we do not allocate general and administrative expense by segment, we measure the performance of our segments by the amount of contribution margin generated in operations. Contribution margin is calculated as net sales less cost of sales and operating expenses. For our wholesale marketing and terminalling segment, we also measure margin per barrel. The gross margin per barrel reflects the gross margin (net sales less cost of sales) of the wholesale marketing operations divided by the number of barrels of refined products sold during the measurement period. Both contribution margin and gross margin per barrel can be affected by fluctuations in the prices of gasoline and distillate fuel.
Operating and Maintenance Expenses.
We seek to maximize the profitability of our operations by effectively managing operating and maintenance expenses. These expenses are comprised primarily of labor expenses, lease costs, utility costs, insurance premiums, repairs and maintenance expenses and property taxes. These expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. We will seek to manage our maintenance expenditures on our pipelines and terminals by scheduling maintenance over time to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flow.
Our operating and maintenance expenses will also be affected by the imbalance gain and loss provisions in our commercial agreements with Delek. Under our commercial agreements with Delek relating to our Lion Pipeline System and our East Texas Crude Logistics System, we bear any crude oil and refined product volume losses on each of our pipelines in excess of 0.25%. Under our commercial agreements with Delek relating to our Memphis and Big Sandy terminals, we will bear any refined product volume losses in each of our terminals in excess of 0.25%. The value of any crude oil or refined product imbalance gains or losses resulting from these contractual provisions is determined by reference to the monthly average reference price for the applicable commodity. Any gains and losses under these provisions will reduce or increase, respectively, our operating and maintenance expenses in the period in which they are realized.
EBITDA and Distributable Cash Flow.
We define EBITDA as net income (loss) before net interest expense, income tax expense, depreciation and amortization expense. We define distributable cash flow as EBITDA less net cash paid for interest, maintenance capital expenditures and income taxes. Distributable cash flow will not reflect changes in working capital balances. Distributable cash flow and EBITDA are not presentations made in accordance with accounting principles generally accepted in the United States ("U.S. GAAP").
EBITDA and distributable cash flow are non-U.S. GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
|
•
|
our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis, or in the case of EBITDA, financing methods;
|
|
•
|
the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
|
|
•
|
ability to incur and service debt and fund capital expenditures; and
|
|
•
|
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
|
We believe that the presentation of EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because EBITDA and distributable cash flow may be defined differently by other companies in our industry,
69
our definition of EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. For a reconciliation of EBITDA to its most directly comparable financial measures calculated and presented in accordance with U.S. GAAP, please refer to "—Results of Operations."
Factors Affecting the Comparability of Our Financial Results
Our future results of operations may not be comparable to our historical results of operations for the reasons described below:
Revenues.
There are differences between the way the Predecessors recorded revenues and the way the Partnership records revenues after the completion of the Offering and any subsequent acquisitions. Because our assets, including the Tyler Terminal and Tank Assets, were historically a part of the integrated operations of Delek, the Predecessors generally recognized the costs and most revenue associated with the gathering, pipeline, transportation, terminalling and storage services provided to Delek on an intercompany basis or charged low throughput fees for transportation. Accordingly, the revenues in the Predecessors' consolidated financial statements are different than those reflected in the Partnership's consolidated financial statements as the Predecessors' amounts relate primarily to amounts received from third parties while the Partnership's revenues will also reflect amounts associated with our commercial agreements with Delek in addition to amounts received from third parties.
The Partnership's revenues are generated from the commercial agreements that we entered into with Delek and from agreements with third parties under which we receive fees for gathering, transporting and storing crude oil and marketing, transporting, storing and terminalling intermediate and refined products. Certain of these contracts contain minimum volume commitments and fees that are indexed for inflation. In addition, the tariff rates for our assets that are subject to FERC regulation will be adjusted annually on July 1 of each year in accordance with FERC’s indexing methodology. We expect to generate revenue from ancillary services, such as ethanol blending and additive injection, and from transportation and terminalling fees on our pipeline systems and terminals for volumes in excess of minimum volume committed under our agreements with Delek. In contrast to the Predecessors, the Partnership does not make bulk biofuel sales in our west Texas marketing operations.
General and Administrative Expenses.
The Predecessors' general and administrative expenses included direct monthly charges for the management and operation of our logistics assets and certain expenses allocated by Delek for general corporate services, such as treasury, accounting and legal services. These expenses were charged or allocated to the Predecessors based on the nature of the expenses and our proportionate share of employee time and headcount.
Delek continues to charge the Partnership for the management and operation of our logistics assets, including an annual fee of $3.0 million for the provision of various centralized corporate services. Additionally, the Partnership is required to reimburse Delek for direct or allocated costs and expenses incurred by Delek on behalf of the Partnership. The Partnership also incurs additional incremental annual general and administrative expense as a result of being a publicly traded partnership.
Financing.
The Partnership paid a cash distribution to its unit holders at a distribution rate of
$0.415
per unit for the quarter ended
December 31, 2013
(
$1.66
per unit on an annualized basis). Our partnership agreement requires that the Partnership distribute to its unitholders quarterly all of its available cash as defined in the partnership agreement. As a result, the Partnership expects to fund future capital expenditures primarily from operating cash flows, borrowings under the Amended and Restated Credit Agreement and potential future issuances of equity and debt securities.
Income Tax Expenses.
Prior to the Offering, the DKL Predecessor was included in Delek’s consolidated federal income tax return, in which the DKL Predecessor was taxed at the entity level as a C corporation. For periods subsequent to the Offering, the Partnership is treated as a partnership for federal income tax purposes, with each partner being separately taxed on its share of taxable income; therefore, there is no federal income tax expense in our financial statements.
Market Trends.
Our results of operations are impacted by our ability to utilize our existing assets to fulfill the long-term fee-based agreements we have entered into with Delek and with third parties. Overall demand for gathering and terminalling services in a particular area is generally driven by crude oil production in the area, refining economics and access to alternate delivery and transportation infrastructure. Any of these factors is subject to change over time. As part of our overall business strategy, management considers aspects such as location, acquisition and expansion opportunities and factors impacting the utilization of the refineries (and, therefore, throughput volumes) which may impact our performance in the market.
Seasonality and Customer Maintenance Programs
The volume and throughput of crude oil and refined products transported through our pipelines and sold through our terminals and to third parties are directly affected by the level of supply and demand for all of such products in the markets
70
served directly or indirectly by our assets. Supply and demand for such products fluctuates during the calendar year. Demand for gasoline, for example, is generally higher during the summer months than during the winter months due to seasonal increases in motor vehicle traffic. Demand for asphalt products, which is a substantial product of Delek's El Dorado Refinery, is also lower in the winter months. In addition, our refining customers, such as Delek, occasionally slow or shut down operations to perform planned maintenance during the winter, when demand for their products is lower. Accordingly, these factors affect the need for crude oil or finished products by our customers and therefore limit our volumes or throughput during these periods, and our operating results are generally lower during the first and fourth quarters of the year. We believe, however, that many of the potential effects of seasonality on our revenues and contribution margin are substantially mitigated due to our commercial agreements with Delek that include minimum volume and throughput commitments.
Results of Operations
A discussion and analysis of the factors contributing to our results of operations is presented below. The accompanying consolidated financial statements for the periods prior to November 7, 2012 represent our Predecessors' results of operations, while the consolidated financial statements for the period subsequent to November 7, 2012 include the results of operations for the Partnership. The accompanying consolidated financial statements and related notes of the DKL Predecessor and the Partnership have been retrospectively adjusted to include the historical results of the Tyler Terminal and Tank Assets for all periods presented through July 26, 2013. The financial statements, together with the following information, are intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting our future performance.
The following table and discussion is a summary of our results of operations for the years ended
December 31, 2013
,
2012
and
2011
including a reconciliation of EBITDA to net income and net cash provided by (used in) operating activities and distributable cash flow to net income (in thousands, except unit and per unit amounts). Our financial results may not be comparable as our Predecessors recorded revenues, general and administrative expenses and financed operations differently than the Partnership. See "—Factors Affecting the Comparability of Our Financial Results" for additional information.
71
|
Years ended December 31,
|
||||||||||||
|
Statement of Operations Data:
|
2013
(1)
|
2012
(1)
|
2011
(1)(2)
|
|||||||||
|
Predecessors
|
Predecessors
|
|||||||||||
|
Net sales:
|
|
|
||||||||||
|
Pipelines and transportation
|
$
|
60,237
|
|
$
|
33,539
|
|
$
|
21,878
|
|
|||
|
Wholesale marketing and terminalling
|
847,191
|
|
989,047
|
722,201
|
||||||||
|
Total
|
907,428
|
|
1,022,586
|
744,079
|
||||||||
|
Operating costs and expenses:
|
|
|
|
|||||||||
|
Cost of goods sold
|
811,364
|
|
959,434
|
700,505
|
||||||||
|
Operating expenses
|
30,302
|
|
30,397
|
19,467
|
||||||||
|
General and administrative expenses
|
6,856
|
|
9,150
|
6,483
|
||||||||
|
Depreciation and amortization
|
12,436
|
|
10,120
|
6,061
|
||||||||
|
Loss (gain) on sale of assets
|
166
|
|
9
|
|
(2
|
)
|
||||||
|
Total operating costs and expenses
|
861,124
|
|
1,009,110
|
732,514
|
||||||||
|
Operating income
|
46,304
|
|
13,476
|
11,565
|
||||||||
|
Interest expense
|
4,570
|
|
2,682
|
2,011
|
|
|||||||
|
Income before taxes
|
41,734
|
|
10,794
|
9,554
|
||||||||
|
Income tax expense (benefit)
|
757
|
|
(14,024
|
)
|
5,363
|
|
||||||
|
Net income
|
$
|
40,977
|
|
$
|
24,818
|
|
$
|
4,191
|
|
|||
|
Less: (Loss) income attributable to Predecessors
|
(6,853
|
)
|
16,408
|
|
4,191
|
|
||||||
|
Net income attributable to partners
|
$
|
47,830
|
|
$
|
8,410
|
|
$
|
—
|
|
|||
|
Comprehensive income attributable to partners
|
$
|
47,830
|
|
$
|
8,410
|
|
$
|
—
|
|
|||
|
EBITDA
(3)
|
$
|
58,740
|
|
$
|
23,596
|
|
$
|
17,626
|
|
|||
|
|
|
|||||||||||
|
Less: General partner's interest in net income (2%)
|
$
|
957
|
|
168
|
|
|||||||
|
Limited partner's interest in net income
|
46,873
|
|
8,242
|
|
||||||||
|
Net income per limited partner unit:
|
||||||||||||
|
Common units - (basic)
|
$
|
1.95
|
|
$
|
0.34
|
|
||||||
|
Common units - (diluted)
|
$
|
1.93
|
|
$
|
0.34
|
|
||||||
|
Subordinated units - Delek (basic and diluted)
|
$
|
1.95
|
|
$
|
0.34
|
|
||||||
|
Weighted average limited partner units outstanding:
|
||||||||||||
|
Common units - (basic)
|
12,025,249
|
|
11,999,258
|
|
||||||||
|
Common units - (diluted)
|
12,148,774
|
|
11,999,258
|
|
||||||||
|
Subordinated units - Delek (basic and diluted)
|
11,999,258
|
|
11,999,258
|
|
||||||||
|
|
|
|||||||||||
|
Distributable Cash Flow
(3)
|
$
|
43,496
|
|
$
|
8,156
|
|
|
|||||
|
(1)
|
The information presented includes the results of operations of our Predecessors. Prior to the completion of the Offering and the Tyler Acquisition, our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services.
|
72
|
(2)
|
Financial information and operating information (other than the information relating to operations in east and west Texas) for the year ended December 31, 2011 is for the 247 and 12 days that Delek operated the El Dorado Refinery and Paline Pipeline system, respectively, in 2011.
|
|
(3)
|
For a definition of EBITDA and distributable cash flow, see "—How We Evaluate Our Operations—EBITDA and Distributable Cash Flow." Distributable cash flow for the year ended
December 31, 2013
includes net loss related to the Tyler Predecessor.
|
|
(In thousands)
|
Years Ended December 31,
|
|||||||||||
|
2013
(1)
|
2012
(1)
|
2011
(1)
|
||||||||||
|
Predecessors
|
Predecessors
|
|||||||||||
|
|
||||||||||||
|
Reconciliation of EBITDA to net income:
|
||||||||||||
|
Net income
|
$
|
40,977
|
|
$
|
24,818
|
|
$
|
4,191
|
|
|||
|
Add:
|
||||||||||||
|
Income tax expense (benefit)
|
757
|
|
(14,024
|
)
|
5,363
|
|
||||||
|
Depreciation and amortization
|
12,436
|
|
10,120
|
|
6,061
|
|
||||||
|
Interest Expense, net
|
4,570
|
|
2,682
|
|
2,011
|
|
||||||
|
EBITDA
(2)
|
$
|
58,740
|
|
$
|
23,596
|
|
$
|
17,626
|
|
|||
|
Reconciliation of EBITDA to net cash provided by (used in) operating activities:
|
||||||||||||
|
Net cash provided by (used in) operating activities
|
$
|
44,391
|
|
$
|
26,612
|
|
$
|
(10,052
|
)
|
|||
|
Amortization of unfavorable contract liability to revenue
|
2,623
|
|
668
|
|
—
|
|
||||||
|
Amortization of debt issuance costs
|
(1,007
|
)
|
(381
|
)
|
(208
|
)
|
||||||
|
Accretion of asset retirement obligations
|
(216
|
)
|
(187
|
)
|
(173
|
)
|
||||||
|
Deferred taxes
(3)
|
(309
|
)
|
228
|
|
4,328
|
|
||||||
|
(Loss) gain on asset disposals
|
(166
|
)
|
(9
|
)
|
2
|
|
||||||
|
Share-based compensation expense
|
—
|
|
(92
|
)
|
(64
|
)
|
||||||
|
Unit-based compensation expense
|
(464
|
)
|
(1
|
)
|
—
|
|
||||||
|
Changes in assets and liabilities
|
8,561
|
|
(10,434
|
)
|
16,419
|
|
||||||
|
Income taxes
(3)
|
757
|
|
4,510
|
|
5,363
|
|
||||||
|
Interest expense, net
|
4,570
|
|
2,682
|
|
2,011
|
|
||||||
|
EBITDA
(2)
|
$
|
58,740
|
|
$
|
23,596
|
|
$
|
17,626
|
|
|||
|
Reconciliation of distributable cash flow to EBITDA:
|
|
|
||||||||||
|
EBITDA
|
$
|
58,740
|
|
23,596
|
|
|||||||
|
Less: Cash interest, net
(4)
|
3,563
|
|
2,301
|
|
||||||||
|
Less: Maintenance and Regulatory capital expenditures
(5)
|
7,179
|
|
8,054
|
|
||||||||
|
Less: Capital improvement expenditures
(6)
|
2,219
|
|
—
|
|
||||||||
|
Add: Reimbursement from Delek for capital expenditures
(6)
|
837
|
|
—
|
|
||||||||
|
Less: Income tax expense
(3)
|
757
|
|
4,510
|
|
||||||||
|
Add: Non-cash share based compensation expense
|
—
|
|
92
|
|
||||||||
|
Add: Non-cash unit based compensation expense
|
464
|
|
1
|
|
||||||||
|
Less: Amortization of deferred revenue
|
204
|
|
—
|
|
||||||||
|
Less: Amortization of unfavorable contract liability
|
2,623
|
|
668
|
|
||||||||
|
Distributable cash flow
(2)
|
$
|
43,496
|
|
$
|
8,156
|
|
|
|||||
73
|
(1)
|
The information presented includes the results of operations of our Predecessors. Prior to the completion of the Offering and the Tyler Acquisition, our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services.
|
|
(2)
|
For a definition of EBITDA and distributable cash flow, see "—How We Evaluate Our Operations—EBITDA and Distributable Cash Flow." Distributable cash flow for the year ended
December 31, 2013
includes net loss related to the Tyler Predecessor.
|
|
(3)
|
Deferred taxes and income tax expense represent the year to date deferred taxes and tax expense, excluding a one-time tax benefit of
$18.5 million
in 2012. The majority of the Partnership's deferred tax assets and liabilities relates to the DKL Predecessor's conversion from a corporation to a partnership, and, as a result of such conversion, we are not subject to federal income taxes. The conversion from a taxable corporation to a pass-through resulted in this one-time tax benefit.
|
|
(4)
|
Interest expense and cash interest both include commitment fees and interest expense that would have been paid by the DKL Predecessor had the prior credit facility been in place during the period presented and we had borrowed $90 million under the facility at the beginning of the period. Cash interest, net excludes the amortization of debt issuance costs.
|
|
(5)
|
Maintenance and regulatory capital expenditures represent cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets, and for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. Examples of maintenance and regulatory capital expenditures are expenditures for the repair, refurbishment and replacement of pipelines and terminals, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.
|
|
(6)
|
For the year ended December 31, 2013, Delek reimbursed us for certain capital expenditures pursuant to the terms of the Omnibus Agreement.
|
74
The following table is a summary of our results of operations for the year ended
December 31, 2013
, disaggregated to present the results of operations of the Tyler Predecessor (in thousands):
|
Delek Logistics Partners, LP
|
Tyler Terminal and Tank Assets
|
Year Ended December 31, 2013
|
||||||||||
|
Tyler Predecessor
|
||||||||||||
|
Statement of Operations Data:
|
|
|
||||||||||
|
|
|
|||||||||||
|
Net sales:
|
|
|
||||||||||
|
Pipelines and transportation
|
$
|
60,237
|
|
$
|
—
|
|
$
|
60,237
|
|
|||
|
Wholesale marketing and terminalling
|
847,191
|
|
—
|
|
847,191
|
|
||||||
|
Total
|
907,428
|
|
—
|
|
907,428
|
|
||||||
|
Operating costs and expenses:
|
|
|
|
|
||||||||
|
Cost of goods sold
|
811,364
|
|
—
|
|
811,364
|
|
||||||
|
Operating expenses
|
25,801
|
|
4,501
|
|
30,302
|
|
||||||
|
General and administrative expenses
|
6,254
|
|
602
|
|
6,856
|
|
||||||
|
Depreciation and amortization
|
10,686
|
|
1,750
|
|
12,436
|
|
||||||
|
Loss on sale of assets
|
166
|
|
—
|
|
166
|
|
||||||
|
Total operating costs and expenses
|
854,271
|
|
6,853
|
|
861,124
|
|
||||||
|
Operating income (loss)
|
53,157
|
|
(6,853
|
)
|
46,304
|
|
||||||
|
Interest expense
|
4,570
|
|
—
|
|
4,570
|
|
||||||
|
Income (loss) before taxes
|
48,587
|
|
(6,853
|
)
|
41,734
|
|
||||||
|
Income tax expense (benefit)
|
757
|
|
—
|
|
757
|
|
||||||
|
Net income (loss)
|
$
|
47,830
|
|
$
|
(6,853
|
)
|
$
|
40,977
|
|
|||
|
EBITDA
(1)
|
$
|
63,843
|
|
$
|
(5,103
|
)
|
$
|
58,740
|
|
|||
(1)
For a definition of EBITDA, see "—How We Evaluate Our Operations—EBITDA and Distributable Cash Flow."
75
The following tables include reconciliations of EBITDA and distributable cash flow to net income and EBITDA to net cash from operating activities for the year ended
December 31, 2013
, disaggregated to present the results of operations of the Partnership and the Tyler Terminal and Tank Assets through
July 26, 2013
(in thousands):
|
Delek Logistics Partners, LP
|
Tyler Terminal and Tank Assets
|
Year Ended December 31, 2013
|
||||||||||
|
Tyler Predecessor
|
||||||||||||
|
Reconciliation of EBITDA to net (loss) income:
|
||||||||||||
|
Net income (loss)
|
$
|
47,830
|
|
$
|
(6,853
|
)
|
$
|
40,977
|
|
|||
|
Add:
|
||||||||||||
|
Income tax expense
|
757
|
|
—
|
|
757
|
|
||||||
|
Depreciation and amortization
|
10,686
|
|
1,750
|
|
12,436
|
|
||||||
|
Interest expense, net
|
4,570
|
|
—
|
|
4,570
|
|
||||||
|
EBITDA
(1)
|
$
|
63,843
|
|
$
|
(5,103
|
)
|
$
|
58,740
|
|
|||
|
Reconciliation of EBITDA to net cash from operating activities:
|
||||||||||||
|
Net cash provided by (used in) operating activities
|
$
|
49,447
|
|
$
|
(5,056
|
)
|
$
|
44,391
|
|
|||
|
Amortization of unfavorable contract liability to revenue
|
2,623
|
|
—
|
|
2,623
|
|
||||||
|
Amortization of debt issuance costs
|
(1,007
|
)
|
—
|
|
(1,007
|
)
|
||||||
|
Accretion of asset retirement obligations
|
(161
|
)
|
(55
|
)
|
(216
|
)
|
||||||
|
Deferred taxes
|
(309
|
)
|
—
|
|
(309
|
)
|
||||||
|
Loss on sale of assets
|
(166
|
)
|
—
|
|
(166
|
)
|
||||||
|
Unit-based compensation expense
|
(464
|
)
|
—
|
|
(464
|
)
|
||||||
|
Changes in assets and liabilities
|
8,553
|
|
8
|
|
8,561
|
|
||||||
|
Income taxes
|
757
|
|
—
|
|
757
|
|
||||||
|
Interest expense, net
|
4,570
|
|
—
|
|
4,570
|
|
||||||
|
EBITDA
(1)
|
$
|
63,843
|
|
$
|
(5,103
|
)
|
$
|
58,740
|
|
|||
|
Reconciliation of distributable cash flow to EBITDA:
|
||||||||||||
|
EBITDA
(1)
|
$
|
63,843
|
|
$
|
(5,103
|
)
|
$
|
58,740
|
|
|||
|
Less: Cash interest expense, net
(2)
|
3,563
|
|
—
|
|
3,563
|
|
||||||
|
Less: Maintenance and Regulatory capital expenditures
(3)
|
4,038
|
|
3,141
|
|
7,179
|
|
||||||
|
Less: Capital improvement expenditures
(4)
|
1,089
|
|
1,130
|
|
2,219
|
|
||||||
|
Add: Reimbursement from Delek for capital expenditures
(5)
|
837
|
|
—
|
|
837
|
|
||||||
|
Less: Income tax expense
|
757
|
|
—
|
|
757
|
|
||||||
|
Add: Non-cash unit based compensation expense
|
464
|
|
—
|
|
464
|
|
||||||
|
Less: Amortization of deferred revenue
|
204
|
|
—
|
|
204
|
|
||||||
|
Less: Amortization of unfavorable contract liability
|
2,623
|
|
—
|
|
2,623
|
|
||||||
|
Distributable cash flow
(1)
|
$
|
52,870
|
|
$
|
(9,374
|
)
|
$
|
43,496
|
|
|||
76
|
(1)
|
For a definition of EBITDA and distributable cash flow, see "—How We Evaluate Our Operations—EBITDA and Distributable Cash Flow."
|
|
(2)
|
Cash interest, net excludes the amortization of debt issuance costs.
|
|
(3)
|
Maintenance and regulatory capital expenditures represent cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets, and for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. Examples of maintenance and regulatory capital expenditures are expenditures for the repair, refurbishment and replacement of pipelines and terminals, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.
|
|
(4)
|
For the year ended December 31, 2013, Delek reimbursed us for certain capital expenditures pursuant to the terms of the Omnibus Agreement.
|
Consolidated Results of Operations — Comparison of the
Year Ended
December 31, 2013
versus the
Year Ended
December 31, 2012
Contribution margin for the
year ended
December 31, 2013
was
$65.8 million
in
2013
, compared to
$32.8 million
in
2012
, an increase of
$33.0 million
or
100.8%
. The increase in contribution margin was primarily attributable to increases in net sales in our pipelines and transportation segment during the year ended
December 31, 2013
compared to the year ended
December 31, 2012
as a result of the effect of the commercial agreements we entered into with Delek in connection with the Offering and with the acquisition of the Tyler Terminal and Tank Assets, which reflect higher rates for crude oil gathering, crude oil, intermediate and refined products transportation and storage services as compared to the rates charged prior to the execution of the commercial agreements. Revenue on our pipeline assets is generated by charging fees for services including gathering, transporting and storing crude oil, intermediates and refined products. Cost of goods sold is therefore not incurred on these assets, resulting in inherently higher margins. Also contributing to the increase were fees received from a third party following the completion of the Paline Pipeline System.
We generated net sales of
$907.4 million
and
$1,022.6 million
during the years ended
December 31, 2013
and
2012
, respectively, a decrease of
$115.2 million
, or
11.3%
. In the fourth quarter of 2011, we began selling bulk biofuels, primarily to Delek. The Partnership discontinued the sale of bulk biofuels following the Offering, contributing to the decrease in net sales during the the year ended
December 31, 2013
compared to the year ended
December 31, 2012
. The sale of bulk biofuels contributed $198.1 million to net sales for the year ended
December 31, 2012
. Also contributing to the decrease in our net sales were decreases in the average sales prices per gallon of gasoline and diesel. There was a
$0.12
per gallon decrease in the average sales price per gallon of gasoline for the year ended
December 31, 2013
, to
$2.73
per gallon from
$2.85
in the year ended
December 31, 2012
, while the average sales price per gallon of diesel decreased
$0.11
for the year ended
December 31, 2013
to
$3.07
per gallon from
$3.18
in the year ended
December 31, 2012
. These decreases were partially offset by increases in volumes across most of our operating systems. The decrease was also partially offset by service fees received for use of the Paline Pipeline System and by the effect of the new throughput and tankage agreement that went into effect in connection with the acquisition of the Tyler Terminal and Tank Assets. The fees associated with the Paline Pipeline System contributed $6.4 million to net sales in the year ended
December 31, 2013
, and the new throughput and tankage agreement contributed $7.4 million to net sales in the year ended
December 31, 2013
.
Cost of goods sold was
$811.4 million
for the year ended
December 31, 2013
, compared to
$959.4 million
for
2012
, a decrease of $148.0 million, or
15.4%
. The decrease in cost of goods sold was primarily attributable to the discontinuation of the sale of bulk biofuels, which accounted for
$201.6 million
of our cost of sales during the year ended
December 31, 2012
. This decrease was partially offset by increases in sales volumes in our west Texas operations.
Operating expenses were
$30.3 million
for the
year ended
December 31, 2013
, compared to
$30.4 million
for
2012
, a decrease of
$0.1 million
or
0.3%
. The decrease in operating expenses was primarily due to decreases in maintenance costs in the year ended
December 31, 2013
compared to the year ended
December 31, 2012
.
General and administrative expenses were
$6.9 million
for the year ended
December 31, 2013
compared to
$9.2 million
for
2012
, a decrease of
$2.3 million
, or
25.1%
. Our Predecessors' general and administrative expenses included direct monthly charges for the management and operation of our logistics assets and certain expenses allocated by Delek for
77
general corporate services, such as treasury, accounting and legal services. While Delek continued to charge the Partnership for the management and operation of our logistics assets as specified in the Omnibus Agreement, the overall decrease in general and administrative expense was primarily due to decreased cost allocations of certain general corporate services allocated to us during the year ended
December 31, 2013
, compared to the year ended
December 31, 2012
.
Depreciation and amortization was
$12.4 million
and
$10.1 million
for the years ended
December 31, 2013
and
2012
, respectively, an increase of
$2.3 million
, or
22.9%
. This increase was primarily due to the addition of depreciation associated with the completion of a rail connection to Delek's El Dorado Refinery on our Lion Pipeline System, which was placed into service in January 2013, and the reversal of the Paline Pipeline System, which was completed in May 2013. Further contributing to the increase was the addition of depreciation expense associated with the Tyler Terminal and Tank Assets acquired in July 2013.
Interest expense was
$4.6 million
for the year ended
December 31, 2013
, compared to
$2.7 million
for
2012
, an increase of
$1.9 million
, or
70.4%
. This increase is primarily attributable to increases in our deferred financing charges and increases in interest costs as a result of borrowings incurred in connection with our acquisition of the Tyler Terminal and Tank Assets.
Income tax expense (benefit) was
$0.8 million
and
$(14.0) million
during the years ended
December 31, 2013
and
2012
, respectively, an increase of
$14.8 million
. Our effective tax rate was
1.8%
for the year ended
December 31, 2013
, compared to
(129.9)%
for
2012
. The increase in our tax expense and effective tax rate was primarily due to the fact that the Partnership is not subject to federal income taxes as a limited partnership. Income tax expense as of
December 31, 2013
reflects a nominal amount of state income tax. The DKL Predecessor's conversion from a corporation to a partnership resulted in a one-time tax benefit of $18.5 million in 2012.
Consolidated Results of Operations - Comparison of the
Year Ended
December 31, 2012
versus the Year Ended
December 31, 2011
Contribution margin for the
year ended
December 31, 2012
was
$32.8 million
in
2012
, compared to
$24.1 million
in
2011
, an increase of $8.7 million, or 36.1%. The increase in contribution margin was primarily attributable to higher margins achieved on our operations in west Texas in 2012, as compared to the same period of
2011
. Also contributing to the increase were the acquisitions of the Lion Pipeline System and the SALA Gathering System in April 2011 and the Paline Pipeline System in December 2011. Revenue on these acquired assets is generated by charging fees for services including gathering, transporting and storing crude oil. Cost of goods sold is therefore not incurred on these assets, resulting in inherently higher margins.
We generated net sales of
$1,022.6 million
and
$744.1 million
during the years ended
December 31, 2012
and
2011
, respectively, an increase of
$278.5 million
, or
37.4%
. In the fourth quarter of 2011, we began selling bulk biofuels, primarily to Delek. The increase in net sales is attributable primarily to the sale of bulk biofuels, which contributed $198.1 million to the increase in sales for the year ended December 31, 2012. The Partnership discontinued the sale of bulk biofuels following the Offering. Further contributing to the increase were increases in sales volumes and the average sales price per gallon of diesel, which increased $0.12 per gallon in the year ended December 31, 2012 to $3.18 per gallon from $3.06 in the comparable period of 2011.
Cost of goods sold was
$959.4 million
for the year ended December 31, 2012, compared to
$700.5 million
for
2011
, an increase of
$258.9 million
, or
37.0%
. The increase in cost of goods sold was primarily attributable to the sale of bulk biofuels, which began in the fourth quarter of 2011. The sale of bulk biofuels accounted for
$201.6 million
of our cost of sales in our wholesale marketing and terminalling segment for the
year ended
December 31, 2012
. Also contributing to the increase were increases in sales volumes associated with our west Texas operations.
Operating expenses were
$30.4 million
for the
year ended
December 31, 2012
compared to
$19.5 million
for
2011
, an increase of
$10.9 million
, or
56.1%
. The increase in operating expenses was primarily due to the acquisitions of the Lion Pipeline System and the SALA Gathering System in April 2011. Further contributing to the increase were the acquisitions of the Nettleton Pipeline and the Big Sandy terminal in the first quarter of 2012.
General and administrative expenses were
$9.2 million
for the year ended December 31, 2012 compared to
$6.5 million
for 2011, an increase of
$2.7 million
, or 41.5%. The overall increase was primarily due to an increase in salaries and employee benefits. Additional expenses were also incurred as the result of being a publicly traded partnership.
78
Depreciation and amortization was
$10.1 million
and
$6.1 million
for the years ended December 31, 2012 and 2011, respectively, an increase of $4.0 million, or
67.0%
. This increase was primarily due to the addition of depreciation associated with the Paline and Nettleton assets, acquired in the fourth quarter of
2011
and first quarter of
2012
, respectively. Further contributing to the increase was the depreciation associated with the assets of the Lion Pipeline System and the SALA Gathering System, which were both acquired in April 2011.
Interest expense was
$2.7 million
for the year ended December 31, 2012, compared to
$2.0 million
for 2011, an increase of
$0.7 million
, or 35.0%. This increase was primarily attributable to increases in interest costs under our credit facilities caused by changes in debt utilization and interest rates thereunder and increases in our deferred financing charges related to our credit facility refinancing and amendment activities during 2012.
Income tax (benefit) expense was
$(14.0) million
and
$5.4 million
during the years ended December 31, 2012 and 2011, respectively, a decrease of
$19.4 million
. Our effective tax rate was
(129.9)%
for the year ended
December 31, 2012
, compared to
56.1%
for
2011
. The decrease in our effective tax rate in year ended 2012 was primarily due to the fact that the Partnership is not subject to federal income taxes as a limited partnership. Accordingly, our taxable income or loss is included in the federal and state income tax returns of our partners, and the income tax expense as of December 31, 2012 reflects a minimal amount of state income tax for the period beginning November 7, 2012 and ending December 31, 2012.
Operating Segments
We review operating results in two reportable segments: (i) pipelines and transportation and (ii) wholesale marketing and terminalling. Decisions concerning the allocation of resources and assessment of operating performance are made based on this segmentation. Management measures the operating performance of each of its reportable segments based on the segment contribution margin. Segment contribution margin is defined as net sales less cost of sales and operating expenses, excluding depreciation and amortization. Segment reporting is more fully discussed in
Note 13
to our accompanying consolidated financial statements.
Pipelines and Transportation Segment
Our pipelines and transportation segment includes the Lion Pipeline System, the SALA Gathering System, the Paline Pipeline System, the East Texas Crude Logistics System, the Tyler-Big Sandy Pipeline, and the Tyler Tank Assets.
79
The following table and discussion is an explanation of the results of operations of the pipelines and transportation segment, including the historical results of the Tyler Tank Assets, for the years ended
December 31, 2013
,
2012
and
2011
(in thousands):
|
Year Ended December 31,
|
||||||||||||
|
2013
(1)
|
2012
(1)
|
2011
(1) (2)
|
||||||||||
|
Delek Logistics Partners, LP
|
Predecessors
|
Predecessors
|
||||||||||
|
Net sales
|
$
|
60,237
|
|
$
|
33,539
|
|
$
|
21,878
|
|
|||
|
Operating costs and expenses:
|
||||||||||||
|
Cost of goods sold
|
764
|
|
—
|
|
—
|
|
||||||
|
Operating expenses
|
22,903
|
|
24,155
|
|
15,415
|
|
||||||
|
Segment contribution margin
|
$
|
36,570
|
|
$
|
9,384
|
|
$
|
6,463
|
|
|||
|
Throughputs (average bpd)
|
||||||||||||
|
Lion Pipeline System
(2)
:
|
||||||||||||
|
Crude pipelines (non-gathered)
|
46,515
|
|
46,027
|
|
57,442
|
|
||||||
|
Refined products pipelines to Enterprise Systems
|
49,694
|
|
45,220
|
|
45,337
|
|
||||||
|
SALA Gathering System
(2)
|
22,152
|
|
20,747
|
|
17,676
|
|
||||||
|
East Texas Crude Logistics System
|
19,896
|
|
55,068
|
|
55,341
|
|
||||||
|
(1)
|
The information presented includes the results of operations of the Tyler Predecessor. Prior to the completion of the Offering and the Tyler Acquisition, our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services. Volumes for all periods include both affiliate and third-party throughput.
|
|
(2)
|
Throughputs for the year ended December 31, 2011 are for the 247 days Delek operated the El Dorado Refinery following its acquisition in April 2011.
|
80
The following table includes the results of operations of the pipelines and transportation segment for the year ended
December 31, 2013
, disaggregated to present the results of operations of the Partnership and the Tyler Terminal and Tank Assets through July 26, 2013 (in thousands):
|
Delek Logistics Partners, LP
|
Tyler Tank Assets
(1)
|
Year Ended December 31, 2013
|
||||||||||
|
Tyler Predecessor
|
||||||||||||
|
Net sales
|
$
|
60,237
|
|
$
|
—
|
|
$
|
60,237
|
|
|||
|
Operating costs and expenses:
|
||||||||||||
|
Cost of goods sold
|
764
|
|
—
|
|
764
|
|
||||||
|
Operating expenses
|
19,042
|
|
3,861
|
|
22,903
|
|
||||||
|
Segment contribution margin
|
$
|
40,431
|
|
$
|
(3,861
|
)
|
$
|
36,570
|
|
|||
|
Throughputs (average bpd)
|
||||||||||||
|
Lion Pipeline System:
|
||||||||||||
|
Crude pipelines (non-gathered)
|
46,515
|
|
—
|
|
46,515
|
|
||||||
|
Refined products pipelines to Enterprise Systems
|
49,694
|
|
—
|
|
49,694
|
|
||||||
|
SALA Gathering System
|
22,152
|
|
—
|
|
22,152
|
|
||||||
|
East Texas Crude Logistics System
|
19,896
|
|
—
|
|
19,896
|
|
||||||
|
(1)
|
The information presented is for the results of operations of the Tyler Predecessor. Prior to the completion of the Tyler Acquisition, the Tyler Predecessor did not record revenues for storage services.
|
Pipelines and Transportation Segment Operational Comparison of the
Year Ended
December 31, 2013
versus the
Year Ended
December 31, 2012
Contribution margin for the pipelines and transportation segment in the
year ended
December 31, 2013
was
$36.6 million
, or
55.6%
of our combined segment contribution margin, compared to
$9.4 million
, or
28.6%
of our combined segment contribution margin in
2012
. This increase was primarily attributable to the effect of the commercial agreements we entered into with Delek in connection with the Offering and in connection with the acquisition of the Tyler Tank Assets, which reflect higher rates for crude oil gathering, crude oil, intermediate and refined products transportation and storage services as compared to the rates charged prior to the execution of the commercial agreements. Revenue on our pipeline assets is generated by charging fees for services including gathering, transporting and storing crude oil. Cost of goods sold is therefore not incurred on these assets, resulting in inherently higher margins. Also contributing to the increase were fees received from the Paline Pipeline System.
Net sales for the pipelines and transportation segment were
$60.2 million
and
$33.5 million
during the years ended
December 31, 2013
and
2012
, respectively, an increase of
$26.7 million
, or
79.6%
. The increase was primarily attributable to the effect of the commercial agreements we entered into with Delek in connection with the Offering, which reflect higher rates for crude oil gathering, crude oil, intermediates and refined products transportation and storage services as compared to the rates charged prior to the execution of the commercial agreements. Also contributing to the increase was the impact of the new throughput and tankage agreement that went into effect in connection with the acquisition of the Tyler Tank Assets, which contributed $4.3 million to net sales in the year ended
December 31, 2013
. Further contributing to the increase were fees received from the Paline Pipeline System. The fees associated with the Paline Pipeline System contributed $6.4 million to net sales in the year ended
December 31, 2013
.
Operating expenses were
$22.9 million
for the
year ended
December 31, 2013
, compared to
$24.2 million
in
2012
, a decrease of
$1.3 million
, or
5.2%
. The decrease in operating expenses was primarily due to decreases in maintenance costs
81
in the year ended
December 31, 2013
compared to the year ended
December 31, 2012
, particularly in relation to the reduced use of the East Texas Crude Logistics System.
Pipelines and Transportation Segment Operational Comparison of the Year Ended
December 31, 2012
versus the Year Ended
December 31, 2011
Contribution margin for the pipelines and transportation segment in the
year ended
December 31, 2012 was
$9.4 million
, or
28.6%
of our combined segment contribution margin, compared to
$6.5 million
, or
26.8%
of our combined segment contribution margin in 2011. The increase in the pipelines and transportation contribution margin was primarily attributable to the acquisitions of the Lion Pipeline System and SALA Gathering System in April 2011 and the Paline Pipeline System in December 2011. Revenue on these acquired assets is generated by charging fees for services including gathering, transporting and storing crude oil, intermediates and refined products. Cost of goods sold is therefore not incurred on these assets, resulting in inherently higher margins. Also contributing to the increase was the effect of the commercial agreements we entered into with Delek in connection with the Offering.
Net sales for the pipelines and transportation segment were
$33.5 million
and
$21.9 million
during the years ended December 31, 2012 and 2011, respectively, an increase of $11.6 million, or 53.3%. The increase was due primarily to the acquisitions of the Lion Pipeline System and SALA Gathering System in April 2011 and Paline Pipeline System in December 2011. Additionally, our commercial agreements with Delek went into effect at the closing of the Offering and reflect higher rates for crude oil gathering, crude oil, intermediates and refined products transportation and storage services as compared to the rates charged prior to the execution of the commercial agreements.
Operating expenses were
$24.2 million
for the
year ended
December 31, 2012, compared to
$15.4 million
in 2011, an increase of $8.8 million, or 57.1%. This increase in operating expenses was primarily due to the acquisitions of the Lion Pipeline System, SALA Gathering System and Paline Pipeline System during 2011. Further contributing to the increase was the acquisition of the Nettleton Pipeline in January 2012.
Wholesale Marketing and Terminalling
We use our wholesale marketing and terminalling assets to generate revenue by providing wholesale marketing and terminalling services to Delek’s refining operations and to independent third parties.
82
The table and discussion below is an explanation of the results of operations of the wholesale marketing and terminalling segment, including the historical results of the Tyler Terminal, for the years ended
December 31, 2013
,
2012
and
2011
(in thousands):
|
Year Ended December 31,
|
||||||||||||
|
2013
(1)
|
2012
(1)
|
2011
(1)
|
||||||||||
|
Delek Logistics Partners, LP
|
Predecessors
|
Predecessors
|
||||||||||
|
Net sales
|
$
|
847,191
|
|
$
|
989,047
|
|
$
|
722,201
|
|
|||
|
Operating costs and expenses:
|
||||||||||||
|
Cost of goods sold
|
810,600
|
|
959,434
|
|
700,505
|
|
||||||
|
Operating expenses
|
7,399
|
|
6,242
|
|
4,052
|
|
||||||
|
Segment contribution margin
|
$
|
29,192
|
|
$
|
23,371
|
|
$
|
17,644
|
|
|||
|
Operating Information:
|
||||||||||||
|
East Texas - Tyler Refinery sales volumes (average bpd)
(2)
|
58,773
|
|
57,574
|
|
57,047
|
|
||||||
|
West Texas marketing throughputs (average bpd)
(3)
|
18,156
|
|
16,523
|
|
15,493
|
|
||||||
|
West Texas marketing margin per barrel
(3)
|
$
|
2.12
|
|
$
|
2.56
|
|
$
|
1.50
|
|
|||
|
Bulk Biofuels (average bpd)
(4)
|
—
|
|
5,577
|
|
3,022
|
|
||||||
|
Terminalling throughputs (average bpd)
(5)
|
75,438
|
|
15,420
|
|
17,907
|
|
||||||
|
(1)
|
The information presented includes the results of operations of the Tyler Predecessor. Prior to the completion of the Offering and the Tyler Acquisition, our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services. Volumes for all periods include both affiliate and third-party throughput.
|
|
(2)
|
Prior to November 7, 2012, we also marketed jet fuel and petroleum coke. Subsequent to November 7, 2012, we ceased to market jet fuel and petroleum coke. Accordingly, these amounts include jet fuel and petroleum coke for the DKL Predecessor in the year 2011 and 2010 and through November 7, 2012. Jet fuel and petroleum coke are excluded from these amounts subsequent to November 7, 2012.
|
|
(3)
|
Excludes bulk ethanol and biodiesel.
|
|
(4)
|
Prior to November 7, 2012, we also marketed bulk ethanol and biodiesel, beginning in the fourth quarter of 2011. Subsequent to November 7, 2012, we ceased to market bulk ethanol and biodiesel. Accordingly, these amounts are presented for the time period during which we marketed bulk biofuels.
|
|
(5)
|
Consists of terminalling throughputs at our Memphis and Nashville, Tennessee terminals, our North Little Rock, Arkansas Terminal and our Tyler, Texas Terminal. Throughputs for the Nashville and Memphis terminals for the year ended December 31, 2011 are for the 247 days Delek operated the El Dorado Refinery following its acquisition in April 2011. Throughputs for the North Little Rock Terminal are for the 69 days Delek operated the terminal following its acquisition in October 2013. Throughputs for the Tyler Terminal are for the 159 days following the Tyler Acquisition. Barrels per day are calculated for only the days we operated each terminal. Total throughput barrels for the year ended December 31, 2013 were
14.9 million
, which averaged
40,842
bpd for the 365 day period.
|
83
The following table includes the results of operations of the wholesale marketing and terminalling segment for the year ended December 31, 2013, disaggregated to present the results of operations of the Partnership and the Tyler Terminal and Tank Assets through July 26, 2013 (in thousands):
|
Delek Logistics Partners, LP
|
Tyler Terminal
(1)
|
Year Ended December 31, 2013
|
||||||||||
|
Tyler Predecessor
|
||||||||||||
|
Net sales
|
$
|
847,191
|
|
—
|
|
$
|
847,191
|
|
||||
|
Operating Costs and Expenses:
|
||||||||||||
|
Cost of goods sold
|
810,600
|
|
—
|
|
810,600
|
|
||||||
|
Operating expenses
|
6,759
|
|
640
|
|
7,399
|
|
||||||
|
Segment contribution margin
|
$
|
29,832
|
|
$
|
(640
|
)
|
$
|
29,192
|
|
|||
|
Operating Information:
|
|
|||||||||||
|
East Texas - Tyler Refinery sales volumes (average bpd)
(2)
|
58,773
|
|
—
|
|
58,773
|
|
||||||
|
West Texas marketing throughputs (average bpd)
(3)
|
18,156
|
|
—
|
|
18,156
|
|
||||||
|
West Texas marketing margin per barrel
(3)
|
$
|
2.12
|
|
$
|
—
|
|
$
|
2.12
|
|
|||
|
Bulk biofuels (average bpd)
(4)
|
—
|
|
—
|
|
—
|
|
||||||
|
Terminalling throughputs (average bpd)
(5)
|
75,438
|
|
59,800
|
|
77,760
|
|
||||||
|
(1)
|
The information presented is for the results of operations of the Tyler Predecessor. Prior to the completion of the Tyler Acquisition, the Tyler Predecessor did not record revenues for terminalling services.
|
|
(2)
|
Prior to November 7, 2012, we also marketed jet fuel and petroleum coke. Subsequent to November 7, 2012, we ceased to market jet fuel and petroleum coke. Accordingly, these amounts include jet fuel and petroleum coke for the period through November 7, 2012. Jet fuel and petroleum coke are excluded from these amounts subsequent to November 7, 2012.
|
|
(3)
|
Excludes bulk ethanol and biodiesel.
|
|
(4)
|
Prior to November 7, 2012, we also marketed bulk ethanol and biodiesel. Subsequent to November 7, 2012, we ceased to market bulk ethanol and biodiesel.
|
|
(5)
|
Consists of terminalling throughputs at our Memphis and Nashville, Tennessee terminals, our North Little Rock Terminal and our Tyler Terminal. Throughputs for the North Little Rock Terminal are for the 69 days Delek operated the terminal following its acquisition in October 2013. Throughputs for the Tyler Terminal are for the 159 days following the Tyler Acquisition. Throughputs for the Tyler Predecessor are for the 206 days prior to our acquisition of the terminal. Barrels per day are calculated for only the days we operated each terminal. Total throughput barrels for the year ended December 31, 2013 were
14.9 million
, which averaged
40,842
bpd for the 365 day period.
|
Wholesale Marketing and Terminalling Segment Operational Comparison of the
Year Ended
December 31, 2013
versus the
Year Ended
December 31, 2012
Contribution margin for the wholesale marketing and terminalling segment in the
year ended
December 31, 2013
was
$29.2 million
, or
44.4%
of our combined segment contribution margin, compared to
$23.4 million
, or
71.4%
of our combined segment contribution margin in
2012
. The increase in contribution margin was primarily due to the impact of the new throughput and tankage agreement that went into effect in connection with the acquisition of the Tyler Terminal, as cost of goods sold is not incurred on the Tyler Terminal assets, resulting in inherently higher margins.
Net sales for the wholesale marketing and terminalling segment were
$847.2 million
for the
year ended
December 31, 2013
, compared to
$989.0 million
for the
year ended
December 31, 2012
, a decrease of $141.8 million, or
14.3%
. In the fourth quarter of 2011, we began selling bulk biofuels, primarily to Delek. The Partnership discontinued the sale of bulk
84
biofuels following the Offering, which contributed to the decrease in net sales during the year ended
December 31, 2013
compared to the year ended
December 31, 2012
. The sale of bulk biofuels contributed $198.1 million in sales for the year ended December 31, 2012. Also contributing to the decrease were decreases in the average sales prices per gallon of gasoline and diesel. There was a
$0.12
per gallon decrease in the average sales price per gallon of gasoline for the year ended
December 31, 2013
, to
$2.73
per gallon from
$2.85
in the year ended
December 31, 2012
, while the average sales price per gallon of diesel decreased
$0.11
for the year ended
December 31, 2013
to
$3.07
per gallon from
$3.18
in the year ended
December 31, 2012
. These decreases were partially offset by increases in throughput volumes in our operating systems within the wholesale marketing and terminalling segment. The decrease was also partially offset by the effect of the new throughput and tankage agreement that went into effect in connection with the acquisition of the Tyler Terminal. The new throughput and tankage agreement contributed $3.1 million to net sales in the year ended
December 31, 2013
.
Cost of goods sold was
$810.6 million
in the
year ended
December 31, 2013
, compared to cost of goods sold of
$959.4 million
for the same period in
2012
, a decrease of
$148.8 million
, or
15.5%
. The decrease in cost of goods sold was primarily attributable to the discontinuation of the sale of bulk biofuels, which accounted for
$201.6 million
of cost of sales during the year ended
December 31, 2012
. This decrease was partially offset by increases in sales volumes in our west Texas operations.
Operating expenses in the wholesale marketing and terminalling segment were approximately
$7.4 million
and
$6.2 million
, for the years ended
December 31, 2013
and
2012
, respectively, an increase of
$1.2 million
, or
18.5%
. The increase in operating expenses was primarily due to increases in repairs and maintenance costs on the terminalling assets in the
year ended
December 31, 2013
compared to the year ended
December 31, 2012
.
Wholesale Marketing and Terminalling Segment Operational Comparison of the Year Ended
December 31, 2012
versus the Year Ended
December 31, 2011
Contribution margin for the wholesale marketing and terminalling segment in the
year ended
December 31, 2012 was
$23.4 million
, or
71.4%
of our combined segment contribution margin, compared to
$17.6 million
, or
73.2%
of our combined segment contribution margin in 2011. The increase in contribution margin for the wholesale marketing and terminalling segment was primarily attributable to higher margins achieved in our operations in west Texas in 2012, as compared to 2011.
Net sales for the wholesale marketing and terminalling segment were
$989.0 million
for the
year ended
December 31, 2012, compared to
$722.2 million
for the
year ended
December 31, 2011, an increase of
$266.8 million
, or
36.9%
. In the fourth quarter of 2011, we began selling bulk biofuels, primarily to Delek, which contributed $198.1 million to the increase in sales for the year ended
December 31, 2012
. The Partnership discontinued the sale of bulk biofuels following the Offering. Further contributing to the increase were increases in sales volumes and the average sales price per gallon of diesel, which increased $0.12 per gallon in the year ended December 31, 2012 to $3.18 per gallon from $3.06 in the comparable period of 2011.
Cost of goods sold was
$959.4 million
for the
year ended
December 31, 2012, compared to
$700.5 million
for 2011, an increase of
$258.9 million
, or
37.0%
. The increase in cost of goods sold was primarily attributable to the sale of bulk biofuels, which began in the fourth quarter of 2011. The sale of bulk biofuels accounted for
$201.6 million
of our cost of sales in our wholesale marketing and terminalling segment for the
year ended
December 31, 2012
. Also contributing to the increase were increases in sales volumes associated with our west Texas operations.
Operating expenses in the wholesale marketing and terminalling segment were approximately
$6.2 million
and
$4.1 million
for the years ended December 31, 2012 and 2011, respectively, an increase of $2.1 million, or 51.2%. The increase in operating expenses was primarily due to the additional costs associated with the Nashville and Memphis product terminals, which were acquired in April 2011, and to additional costs associated with the Big Sandy terminal, which was acquired in February 2012.
85
Liquidity and Capital Resources
We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our revolving credit facility and potential issuances of additional equity and debt securities. We believe that cash generated from these sources will be sufficient to satisfy the anticipated cash requirements associated with our existing operations, including minimum quarterly cash distributions, for at least the next 12 months.
We paid a cash distribution of
$0.415
per unit for the quarter ended
December 31, 2013
, which equates to
$10.2 million
per quarter, or
$40.9 million
per year, based on the number of common, subordinated and general partner units outstanding. We do not have a legal obligation to pay this distribution.
The table below summarizes the minimum quarterly distributions paid related to
2013
financial results:
|
Quarter Ended
(1)
|
Total Quarterly Distribution Per Unit
|
Total Quarterly Distribution Per Unit, Annualized
|
Total Cash Distribution (in thousands)
|
Date of Distribution
|
||||
|
December 31, 2013
|
$0.415
|
1.66
|
$10,228
|
February 13, 2014
|
||||
|
September 30, 2013
|
$0.405
|
1.62
|
$9,933
|
November 14, 2013
|
||||
|
June 30, 2013
|
$0.395
|
1.58
|
$9,687
|
August 13, 2013
|
||||
|
March 31, 2013
|
$0.385
|
1.54
|
$9,428
|
May 15, 2013
|
||||
|
December 31, 2012 (from November 7, 2012)
(1)
|
$0.224
|
0.896
|
$5,486
|
February 14, 2013
|
||||
|
(1)
|
The quarterly cash distribution for the three months ended December 31, 2012 was calculated as the minimum quarterly cash distribution of $0.375 per unit per quarter, or $1.50 per unit on an annualized basis, prorated for the period beginning November 7, 2012, the date the Partnership commenced operations.
|
Historically, our Predecessors' sources of liquidity included cash generated from operations and borrowings under our Predecessors' revolving credit facility. Delek retained the working capital related to our Predecessors at the completion of the Offering, as those balances represented assets and liabilities related to the Predecessors' assets prior to the completion of the Offering.
Cash Flows
The following table sets forth a summary of our consolidated cash flows for the years ended
December 31, 2013
,
2012
and
2011
(in thousands):
|
|
Year Ended December 31,
|
|||||||||||
|
|
2013
|
2012
|
2011
|
|||||||||
|
Cash Flow Data:
|
|
|||||||||||
|
Cash flows provided by (used in) operating activities
|
$
|
44,391
|
|
$
|
26,612
|
|
$
|
(10,052
|
)
|
|||
|
Cash flows used in investing activities
|
(20,135
|
)
|
(50,010
|
)
|
(7,130
|
)
|
||||||
|
Cash flows (used in) provided by financing activities
|
(46,784
|
)
|
46,815
|
|
17,217
|
|
||||||
|
Net (decrease) increase in cash and cash equivalents
|
$
|
(22,528
|
)
|
$
|
23,417
|
|
$
|
35
|
|
|||
Cash Flows from Operating Activities
Net cash provided by operating activities was
$44.4 million
for the year ended
December 31, 2013
, compared to
$26.6 million
for
2012
. The increase in cash flows from operations in the
year ended
2013
from the same period in
2012
was primarily due to higher revenues as a result of our commercial agreements executed concurrent with and subsequent to the Offering and the acquisition of the Tyler Terminal and Tank Assets. Net income for the year ended
December 31, 2013
was
$41.0 million
, compared to net income of
$24.8 million
in
2012
.
Net cash provided by operating activities was
$26.6 million
for the year ended December 31, 2012, compared to cash used in operating activities of
$10.1 million
for 2011. The increase in cash flows from operations in the
year ended
2012 from the same period in 2011 was primarily due to increases in accounts payable to related parties and decreases in inventories and other current assets, partially offset by increases in deferred income taxes and decreases in accounts payable and other current liabilities. Net income for the year ended December 31, 2012 was
$24.8 million
, compared to net income of
$4.2 million
in 2011.
86
Cash Flows from Investing Activities
Net cash used in investing activities was
$20.1 million
for the year ended
December 31, 2013
, compared to
$50.0 million
used in
2012
. Cash used in investing activities includes capital expenditures for
2013
of approximately $9.4 million, of which $6.9 million was spent on projects in the pipelines and transportation segment and $2.5M was spent in the wholesale marketing and terminalling segment. The total expenditures made during the year ended December 31, 2013 related primarily to the Tyler Terminal and Tank Assets and our Lion Pipeline System. Of the total expenditures made during the year ended
December 31, 2013
, approximately $4.3 million related to the Tyler Terminal and Tank Assets and $3.4 million related to the Lion Pipeline System. Cash paid for the acquisitions of the Hopewell Pipeline and the North Little Rock Terminal accounted for $10.7 million of the cash used in investing activities for the year ended
December 31, 2013
. Cash used in investing activities made during the year ended
December 31, 2012
related primarily to the acquisitions of the Nettleton Pipeline and the Big Sandy assets, which accounted for approximately $12.3 million and $11.0 million, of total capital expenditures. Also contributing to the cash used in investing activities for the year ended
December 31, 2012
were capital expenditures of $26.8 million, which related primarily to the Tyler Terminal and Tank Assets and the Lion Pipeline System assets. Of the total expenditures made during the year ended
December 31, 2012
, approximately $15.7 million and $7.2 million related to the Tyler Terminal and Tank Assets and the Lion Pipeline System, respectively.
Net cash used in investing activities was
$50.0 million
for the year ended
December 31, 2012
, compared to
$7.1 million
in 2011. This increase was primarily due to $23.3 million in cash paid for the acquisitions of both the Nettleton Pipeline and Big Sandy assets in the first quarter of 2011. Cash used in investing activities includes capital expenditures for 2012 of approximately $26.8 million, of which $22.1 million was spent on projects in the pipelines and transportation segment and $4.7 million was spent on projects in the wholesale marketing and terminalling segment. Capital expenditures made during the year ended
December 31, 2012
relate primarily to the Tyler Terminal and Tank Assets and to our Lion Pipeline System. Of the total expenditures made during the year ended
December 31, 2012
, approximately $15.7 million relates to the Tyler Terminal and Tank Assets and $7.2 million relates to the Lion Pipeline System.
Cash Flows from Financing Activities
Net cash used in financing activities was
$46.8 million
in the year ended
December 31, 2013
, compared to cash provided of
$46.8 million
in
2012
. We paid quarterly cash distributions totaling $34.5 during the year ended
December 31, 2013
. Additionally, we paid $94.8 million in exchange for assets included in the Tyler Acquisition. Offsetting the cash used in financing activities were net proceeds of $74.8 million under the Amended and Restated Credit Agreement compared to net proceeds of $59.7 million during the same period in 2012.
Net cash provided by financing activities was
$46.8 million
in the year ended December 31, 2012, compared to cash provided of
$17.2 million
in 2011. The increase in net cash from financing activities in 2012 was primarily a result of transactions related to the Offering. We received net proceeds of
$171.8 million
from the sale of
9,200,000
common units in the Offering, after deducting offering costs and debt issuance costs of
$17.7 million
and
$3.7 million
, respectively, and we retained
$30.5 million
of the proceeds for working capital purposes before the cash distribution to Delek. We repaid the outstanding balance of $63.0 million on the DKL Predecessor's revolving credit facility with Fifth Third Bank, which was terminated in conjunction with the Offering. We also borrowed $90.0 million under the prior credit facility at the completion of the Offering. We distributed
$231.3 million
to Delek in consideration for contributed assets and to reimburse Delek for certain capital expenditures incurred with respect to the contributed assets.
As of
December 31, 2013
, our total cash and cash equivalents were
$0.9 million
and we had total indebtedness of
$164.8 million
. Borrowing availability under the Amended and Restated Credit Agreement was
$223.2 million
and we had letters of credit issued of
$12.0 million
. We believe we were in compliance with the applicable covenants in our debt facility as of
December 31, 2013
.
On July 9, 2013, the Partnership amended and restated its senior secured revolving credit agreement, which it originally entered into on November 7, 2012, with Fifth Third Bank, as administrative agent, and a syndicate of lenders. Under the terms of the Amended and Restated Credit Agreement, the lender commitments were increased from $175.0 million to $400.0 million and a dual currency borrowing tranche was added that permits draw downs in U.S. or Canadian dollars. The maturity date remains November 7, 2017 under the Amended and Restated Credit Agreement.
We and each of our existing subsidiaries are borrowers under the credit facility. The Amended and Restated Credit Agreement also contains an accordion feature whereby we can increase the size of the credit facility to an aggregate of $450.0 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent.
87
The credit facility is generally available to fund working capital, finance acquisitions and other capital expenditures, fund certain future distributions and for other general partnership purposes. We borrowed $90.0 million under the prior credit facility at the completion of the Offering in order to fund a cash distribution to Delek Marketing in partial consideration of the contribution of assets to us and in part for reimbursement of capital expenditures associated with our assets. In connection with our cash distribution to Delek Marketing at the time of the Offering, we agreed to retain at least $90.0 million in outstanding debt, either under our credit facility or as a result of certain refinancings thereof, until November 2015.
The obligations under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of the Partnership's and its U.S. subsidiaries' tangible and intangible assets. Additionally, Delek Marketing provides a limited guaranty of the Partnership's obligations under the Amended and Restated Credit Agreement. Delek Marketing's guaranty is (i) limited to an amount equal to the principal amount, plus unpaid and accrued interest, of a promissory note made by Delek in favor of Delek Marketing (the "Holdings Note") and (ii) secured by Delek Marketing's pledge of the Holdings Note to our lenders under the Amended and Restated Credit Agreement. As of
December 31, 2013
, the principal amount of the Holdings Note was $102.0 million, plus unpaid interest accrued since the issuance date.
The Amended and Restated Credit Agreement contains various covenants and restrictive provisions customary for credit facilities of this nature. Financial covenants include an interest coverage ratio defined as the ratio of consolidated EBITDA (as defined in the agreement) to cash interest expense, tested quarterly, for the four fiscal quarters then ended of not less than 2.50 to 1.00 (previously 2.00 to 1.00) and a leverage ratio defined as total funded debt to consolidated EBITDA, tested quarterly, for the four fiscal quarters then ended of not greater than 4.00 to 1.00 (previously 3.50 to 1.00).
Borrowings denominated in U.S. dollars under the Amended and Restated Credit Agreement bear interest at either a U.S. dollar prime rate, plus an applicable margin, or LIBOR, plus an applicable margin, at the election of the borrowers. Borrowings denominated in Canadian dollars under the Amended and Restated Credit Agreement bear interest at either a Canadian dollar prime rate, plus an applicable margin, or CDOR, plus an applicable margin, at the election of the borrowers. The applicable margin in each case varies based upon the Partnership's most recently reported leverage ratio. Additionally, the Amended and Restated Credit Facility requires us to pay a leverage ratio-dependent quarterly fee on the average unused revolving commitment.
The Amended and Restated Credit Agreement contains events of default customary for credit facilities of this nature. They include, but are not limited to, the failure to pay any principal, interest or fees when due, failure to satisfy any covenant, untrue representations or warranties, impairment of liens, events of default under any other loan document under the credit facility, default under any other material debt agreements, insolvency, certain bankruptcy proceedings, change of control (which will occur if, among other things, (i) Delek ceases to own and control legally and beneficially at least 51% of the equity interests of our general partner, (ii) Delek Logistics GP, LLC ceases to be our sole general partner or (iii) the Partnership fails to own and control legally and beneficially 100% of the equity interests of any other borrower under the Amended and Restated Credit Agreement, unless otherwise permitted thereunder) and material litigation resulting in a final judgment against any borrower or guarantor that remains undischarged or unstayed. Upon the occurrence and during the continuation of an event of default under the Amended and Restated Credit Agreement, the lenders may, among other things, accelerate and declare the outstanding loans to be immediately due and payable and exercise remedies against the Partnership, its subsidiaries and the collateral as may be available to the lenders under the Amended and Restated Credit Agreement and other loan documents.
Agreements Governing Certain Indebtedness of Delek
Although we are not contractually bound by and are not liable for Delek’s debt under its credit arrangements, we are indirectly affected by certain prohibitions and limitations contained therein. Specifically, under the terms of certain of Delek's credit arrangements, we expect that Delek will be in default if we incur any indebtedness for borrowed money in excess of $300.0 million at any time outstanding, which amount is subject to increase for (i) certain acquisitions of additional or newly constructed assets and for growth capital expenditures, in each case, net of asset sales, and for (ii) certain types of debt, such as debt obligations owed under hedge agreements, intercompany debt of the Partnership and our subsidiaries and debt under certain types of contingent obligations. These arrangements also require that Delek maintain (i) consolidated shareholders’ equity of at least $700.0 million and (ii) a ratio of consolidated shareholders’ equity to adjusted total assets, which is defined as total assets less cash and certain liabilities, of at least 0.35 to 1.00. Although these covenants do not currently limit our ability to use the full capacity available under our revolving credit facility, we cannot assure you that such covenants will not impact such ability in the future. Delek, due to its majority ownership and control of our general partner, has the ability to prevent us from taking actions that would cause Delek to violate any covenant in its credit arrangements or otherwise be in default under any of its credit arrangements. Please read “Item 1A—Risk Factors—Risks Relating to Our Business—Delek’s level of indebtedness, the terms of its borrowings and any future credit ratings could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit profile. Our ability to obtain credit in the future and our future credit rating may also be affected by Delek’s level of indebtedness.”
88
Capital Spending
A key component of our long-term strategy is our capital expenditure program. Our capital expenditures for the year ended
December 31, 2013
, excluding capital spending related to the Tyler Terminal and Tank Assets, were
$5.1 million
, of which approximately
$2.7 million
was spent in our pipelines and transportation segment and approximately
$2.5 million
was spent in our wholesale marketing and terminalling segment. Our capital expenditure budget is approximately
$20.4 million
for
2014
.
The following table summarizes our actual capital expenditures for the year ended
December 31, 2013
and planned capital expenditures for the full year
2014
by operating segment and major category (in thousands):
|
Year Ended December 31,
|
||||||||
|
2014 Forecast
|
2013 Actual
(3)
|
|||||||
|
Pipelines and Transportation:
|
|
|
||||||
|
Regulatory
|
$
|
1,332
|
|
$
|
320
|
|
||
|
Maintenance
(1)
|
4,532
|
|
1,576
|
|
||||
|
Discretionary projects
(2)
|
3,513
|
|
763
|
|
||||
|
Pipelines and transportation segment total
|
$
|
9,377
|
|
$
|
2,659
|
|
||
|
Wholesale Marketing and Terminalling:
|
|
|
||||||
|
Regulatory
|
$
|
—
|
|
$
|
—
|
|
||
|
Maintenance
(1)
|
3,600
|
|
2,143
|
|
||||
|
Discretionary projects
(2)
|
7,414
|
|
326
|
|
||||
|
Wholesale marketing and terminalling segment total
|
11,014
|
|
2,469
|
|
||||
|
Total capital spending
|
$
|
20,391
|
|
$
|
5,128
|
|
||
|
(1)
|
Maintenance capital expenditures represent cash expenditures (including expenditures for improvements to, or the replacement of, our capital assets, made to maintain our long-term operating income or operating capacity. Examples of maintenance capital expenditures are expenditures for the repair, refurbishment and replacement of pipelines and terminals, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. Delek has agreed to reimburse us with respect to assets it has transferred to us for all non-discretionary maintenance capital expenditures, other than those required to comply with applicable environmental laws and regulations, in excess of specified dollar amounts for a period of five years.
|
|
(2)
|
Delek has agreed to reimburse us for certain discretionary expenditures, including those in connection with certain capital improvements that were in progress as of November 7, 2012.
|
|
(3)
|
The actual capital spending does not include capital expenditures prior to July 26, 2013 of $4.3 million related to the assets acquired in the Tyler Acquisition.
|
For the full year
2014
, we plan to spend approximately
$1.3 million
on regulatory projects in the pipelines and transportation segment. We spent
$0.3 million
on regulatory projects in the year ended
December 31, 2013
. In addition, we plan to spend approximately
$4.5 million
on maintenance projects and approximately
$3.5 million
for other discretionary projects in
2014
. Of the
$11.0 million
budgeted for the wholesale marketing and terminalling segment,
$7.4 million
is allocated to discretionary projects in the year ended December 31, 2013. The majority of the amount budgeted to this segment is related to the expansion of the North Little Rock Terminal.
Under the Omnibus Agreement, Delek has agreed to reimburse us for certain expenses that we incur for inspections, maintenance and repairs to any storage tanks we acquired in the Tyler Acquisition to cause such storage tanks to comply with applicable regulatory and/or industry standards. See "Item 1—Business—Commercial Agreements—Other Agreements with Delek—Omnibus Agreement" for more information on the reimbursement provisions specified in the agreement. Pursuant to the Omnibus Agreement, Delek is required to reimburse us for certain expenses that we incur for inspections, maintenance and repairs to any of the storage tanks contributed to us by Delek (subject to a deductible of $0.5 million per year) that are necessary to comply with the DOT pipeline integrity rules and certain American Petroleum Institute storage tank standards for a period of five years. Furthermore, Delek was required to reimburse us for all non-discretionary maintenance capital expenditures with respect to the Tyler Terminal and Tank Assets in excess of $0.4 million for the period from July 26, 2013 through September 30, 2013. Delek was also required to reimburse us for non-discretionary maintenance capital expenditures with respect to all assets transferred from Delek to the Partnership in excess of $1.35 million for the period from September 30, 2013 through December 31, 2013. Delek will reimburse us for all non-discretionary maintenance capital expenditures with respect to the El
89
Dorado Terminal and Tank Assets in excess of $4.0 million for the period from February 10, 2014 through December 2014. In addition, Delek will reimburse us for non-discretionary maintenance capital expenditures with respect to certain assets transferred from Delek to the Partnership in excess of (i) $5.4 million for calendar year 2014; (ii) $9.8 million in any calendar year beginning with calendar year 2015 and ending with calendar year 2017; and (iii) $4.4 million in any calendar year beginning with calendar year 2018 and ending February 2019.
In addition to these reimbursement obligations, Delek reimbursed us for discretionary capital expenditures in connection with certain capital improvements that were in progress as of November 7, 2012. The first of these improvements was an addition to our Lion Pipeline System to transport crude oil to the El Dorado Refinery from a rail delivery adjacent to such refinery. Delek reimbursed us a nominal amount for the remaining costs of constructing this pipeline in the first quarter of 2013. Delek also reimbursed us $0.1 million in the first quarter of 2013 for the remainder of the costs incurred to complete the reversal of the Paline Pipeline System. In addition, Delek reimbursed us $0.2 million in each of the first and second quarters of 2013 for capital improvements necessary to enable bi-directional flow on our Nettleton Pipeline.
The amount of our capital expenditure budget is subject to change due to unanticipated increases in the cost, scope and completion time for our capital projects. For example, we may experience increases in the cost of and/or timing to obtain necessary equipment required for our continued compliance with government regulations or to complete improvement projects. Additionally, the scope and cost of employee or contractor labor expense related to installation of that equipment could increase from our projections.
Contractual Obligations and Commitments
Information regarding our known contractual obligations of the types described below as of
December 31, 2013
, is set forth in the following table (in thousands)
|
<1 Year
|
1-3 Years
|
3-5 Years
|
>5 Years
|
Total
|
||||||||||||||||
|
Long term debt, notes payable and capital lease obligations
|
$
|
—
|
|
$
|
—
|
|
$
|
164,800
|
|
$
|
—
|
|
$
|
164,800
|
|
|||||
|
Interest
(1)
|
4,241
|
|
8,493
|
|
3,613
|
|
—
|
|
16,347
|
|
||||||||||
|
Total
|
$
|
4,241
|
|
$
|
8,493
|
|
$
|
168,413
|
|
$
|
—
|
|
$
|
181,147
|
|
|||||
|
(1)
|
Includes expected interest payments on debt outstanding under our credit facility in place at December 31, 2013. Floating interest rate debt is calculated using December 31, 2013 rates.
|
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements through the date of this Annual Report on Form 10-K.
Critical Accounting Policies
Our significant accounting policies are described in Note 2 to our audited consolidated financial statements. We prepare our consolidated financial statements in conformity with U.S. GAAP, and in the process of applying these principles, we must make judgments, assumptions and estimates based on the best available information at the time. To aid a reader’s understanding, management has identified our critical accounting policies. These policies are considered critical because they are both most important to the portrayal of our financial condition and results, and require our most difficult, subjective or complex judgments. Often they require judgments and estimation about matters which are inherently uncertain and involve measuring, at a specific point in time, events which are continuous in nature. Actual results may differ based on the accuracy of the information utilized and subsequent events, of which we may have little or no control.
Property, Plant and Equipment and Intangibles Impairment
Property, plant and equipment and definite life intangibles are evaluated for impairment whenever indicators of impairment exist. Accounting standards require that if an impairment indicator is present, we must assess whether the carrying amount of the asset is unrecoverable by estimating the sum of the future cash flows expected to result from the asset, undiscounted and without interest charges. We derive the required undiscounted cash flow estimates from our historical experience and our internal business plans. We use quoted market prices when available and our internal cash flow estimates discounted at an appropriate interest rate to determine fair value, as appropriate. If the carrying amount is more than the recoverable amount, an impairment charge must be recognized based on the fair value of the asset.
90
Goodwill and Potential Impairment
Goodwill is reviewed at least annually for impairment or more frequently if indicators of impairment exist. Goodwill is tested by comparing net book value of the operating segments to the estimated fair value of the reporting unit. In assessing the recoverability of goodwill, assumptions are made with respect to future business conditions and estimated expected future cash flows to determine the fair value of a reporting unit. We use a market participant weighted average cost of capital, estimated minimal growth rates for revenue, gross profit, and capital expenditures based on history and our best estimate of future forecasts. We also estimate the fair values of our reporting units using a multiple of expected future cash flows, such as those used by third party analysts. If these estimates and assumptions change in the future due to such factors as a decline in general economic conditions, competitive pressures on sales and margins, and other economic and industry factors beyond management’s control, an impairment charge may be required.
New Accounting Pronouncements
In July 2012, the FASB issued guidance regarding testing indefinite-lived intangible assets for impairment that gives companies the option to perform a qualitative assessment before calculating the fair value of the indefinite-lived intangible asset. Under the guidance, if this option is selected, a company is not required to calculate the fair value of the indefinite-lived intangible asset unless the entity determines it is more likely than not that its fair value is less than its carrying amount. In October 2012, the FASB issued guidance regarding the application of the qualitative assessment permitted under the Accounting Standards Update 2012-02, issued in July of the same year. The guidance requires companies to focus on the significant inputs used to determine the fair value of indefinite-lived intangible assets when companies opt to perform the qualitative assessment. Companies must then evaluate the impact of certain events and circumstances that could have affected those inputs and weigh the identified factors prior to concluding whether the asset is impaired. As significant judgment is applied to conclude that an indefinite-lived intangible asset is not impaired based on a qualitative assessment, the analyses performed by the company should be supported by clear documentation of the factors considered, including any necessary quantitative calculations. The guidance is effective for interim and annual reporting periods beginning January 1, 2013, but early adoption is permitted. The adoption of this guidance did not affect our business, financial position or results of operations.
In December 2011, the FASB issued guidance requiring the disclosure of information about offsetting and related arrangements to enable users of financial statements to understand the effect of these arrangements on financial position. The guidance requires the disclosure of both gross information and net information about both instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master netting arrangement. In January 2013, the FASB issued an update limiting the scope of the offsetting disclosure requirements established by the original guidance to certain derivatives (including bifurcated embedded derivatives), repurchase agreements and reverse repurchase agreements, and securities lending and securities borrowing transactions that are eligible for offset on the balance sheet or are subject to an agreement similar to a master netting arrangement, irrespective of whether they are offset on the balance sheet. This update amends the guidance that required companies to apply the requirements to all recognized financial instruments. The original and updated guidance is effective for interim and annual reporting periods beginning January 1, 2013 and retrospectively for all periods presented on the balance sheet. The adoption of this guidance did not affect our business, financial position or results of operations. but resulted in additional disclosures.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk.
Market risk is the risk of loss arising from adverse changes in market rates and prices. As we do not take title to any of the crude oil that we handle, and we take title to only limited volumes of light products in our marketing business, we have minimal direct exposure to risks associated with fluctuating commodity prices. However, from time to time, we enter into Gulf Coast product swap arrangements with respect to the products we purchase to hedge our exposure to fluctuations in commodity prices for the period between our purchase of products from, and subsequent sales to, our customers. At
December 31, 2013
, we held no outstanding swap contracts. We held a nominal amount of outstanding swap contracts at
December 31, 2012
. Please read
Note 15
to our accompanying consolidated financial statements for additional detail related to our derivative instruments. In addition, the Partnership's commercial agreements with Delek are indexed to inflation.
Interest Rate Risk.
Debt that we incur under our revolving credit facility bears interest at a variable rate and will expose us to interest rate risk. From time to time, we may use certain derivative instruments to hedge our exposure to variable
91
interest rates. Additionally, our prior revolving credit facility required us to maintain interest rate hedging arrangements with respect to at least 50% of the amount funded on November 7, 2012 under the credit facility, which was required to be in place for at least a three-year period beginning no later than March 7, 2013. Effective February 25, 2013, and as of December 31, 2013, we had in place an interest rate hedge in the form of a LIBOR interest rate cap with a term of three years for a total notional amount of $45.0 million, thereby meeting this requirement.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by Item 8 is incorporated by reference to the section beginning on page F-1.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our management has evaluated, with the participation of our principal executive and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e)) under the Exchange Act as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting during the fourth quarter of fiscal
2013
that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management's Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process that is designed under the supervision of our Chief Executive Officer and Chief Financial Officer, and implemented by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. Our internal control over financial reporting includes those policies and procedures that:
|
i.
|
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
|
|
ii.
|
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that receipts and expenditures recorded by us are being made only in accordance with authorizations of our management and Board of Directors; and
|
|
iii.
|
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
|
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
Management has conducted its evaluation of the effectiveness of internal control over financial reporting as of
December 31, 2013
, based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management's assessment included an evaluation of the design of our internal control over financial reporting and testing the operational effectiveness of our internal control over financial reporting. Management reviewed the results of the assessment with the Audit Committee of the Board of Directors. Based on its assessment and review with the Audit Committee, management concluded that, at
December 31, 2013
, we maintained effective internal control over financial reporting.
Report of Independent Registered Public Accounting Firm
Our independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of our internal control over financial reporting as of
December 31, 2013
, as stated in their report, which is included in the section beginning on page F-1.
The information required by Item 8 is incorporated by reference to the section beginning on page F-1.
ITEM 9B.
OTHER INFORMATION
None.
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ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Our general partner, Delek Logistics GP, LLC, is an indirect subsidiary of Delek. Three individuals who serve as both directors and executive officers of the general partner, Messrs. Yemin, Ginzburg and Green, also own membership interests of 3.0%, 0.2% and 0.2%, respectively, in the general partner. Mr. Yemin also holds unvested awards of membership interests that, once fully vested, will increase his membership interest to 5.0%. Our general partner manages our operations and activities on our behalf through its officers and directors. References in this Part III to the "Board," "directors," or "officers" refer to our Board, directors and officers of our general partner.
The Board of Directors of Our General Partner
The directors of our general partner oversee our operations. The members of our Board are not elected by our unitholders and will not be subject to re-election by our unitholders in the future. The general partner is a limited liability company and its directors are elected by its members, all of which are subsidiaries, affiliates, directors, officers and/or employees of Delek. The directors hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly without recourse to the general partner. Our general partner therefore may cause us to incur indebtedness or other obligations that are without recourse to the general partner.
Our common units are traded on the NYSE. Because we are a limited partnership, we rely on an exemption from the provisions of Section 303A.01 of the NYSE Listed Company Manual which would otherwise require the Board to be composed of a majority of independent directors. In addition, we are not required to establish either a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members, and all of our audit committee members are required to meet the independence and experience tests established by the NYSE and the Exchange Act.
At the date of this report, the Board consists of the following seven members: Ezra Uzi Yemin, Charles J. Brown, III, Mark B. Cox, Eric D. Gadd, Assaf Ginzburg, Frederec Green and Gary M. Sullivan, Jr. The Board has determined that each of Messrs. Brown, Gadd and Sullivan qualifies as an independent director under applicable SEC rules and regulations and the rules of the NYSE. Under the NYSE's listing standards, a director will not be deemed independent unless the Board affirmatively determines that the director has no material relationship with us. Based upon information requested from and provided by each director concerning his background, employment and affiliations, including commercial, industrial, banking, consulting, legal, accounting, charitable and familial relationships, the Board has determined that each of Messrs. Brown, Gadd and Sullivan has no material relationship with Delek or us, either directly or as a partner, stockholder or officer of an organization that has a relationship with Delek or us, and each of them is therefore independent under the NYSE's listing standards and applicable SEC rules and regulations.
Director Experience and Qualifications
The members of the general partner are responsible for filling vacancies on the Board at any time during the year, and for selecting individuals to serve on the Board. From time to time, the members may utilize the services of search firms or consultants to assist in identifying and screening potential candidates. In accordance with the general partner's Governance Guidelines, in evaluating potential Board candidates, the members consider such qualifications and other factors as they deem appropriate, including the individual’s independence, education, experience, reputation, judgment, skill, integrity and industry knowledge. Directors should have experience in positions with a high degree of responsibility; be leaders in the organizations with which they are affiliated; and have the time, energy, interest and willingness to serve as a member of the Board. In determining fitness for service on the Board, there is no policy for considering racial or ethnic classifications, gender, religion or sexual orientation, but the members may consider the individual’s contribution to the Board’s overall diversity, the degree to which the individual’s qualities and attributes will complement those of other directors, and the extent to which the candidate would be a desirable addition to the Board and committees thereof.
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Executive Officers of Our General Partner
Our general partner's executive officers manage the day-to-day affairs of our business and conduct our operations. The executive officers of our general partner are appointed by the Board and serve in that capacity at the discretion of the Board. All of our general partner's executive officers are employees of Delek. While the amount of time that our general partner's executive officers devote to our business varies in any given year, we currently estimate that approximately 10% to 20% of their productive business time is spent on the management and conduct of our operations. The executive officers of our general partner intend, however, to devote as much of their time as is necessary for the proper conduct of our business. We also utilize a significant number of Delek's employees to operate our business and provide us with general and administrative services. Under the Omnibus Agreement, we pay Delek an annual fee, indexed for inflation, for Delek's provision of centralized corporate services, including executive management services of Delek employees who devote less than 50% of their time to our business, financial and administrative services, information technology services, legal services, health, safety and environmental services, human resource services, and insurance administration. In addition, we reimburse Delek for allocated expenses of personnel who devote 50% or more of their time performing services for our benefit. Please see "Item 1—Commercial Agreements—Other Agreements with Delek—Omnibus Agreement" for a more complete discussion of the services provided by Delek to us.
Directors and Executive Officers of Our General Partner
The following table shows information for the directors and executive officers of our general partner.
|
Name
|
Age
|
Position With Delek Logistics GP, LLC
|
|
Ezra Uzi Yemin
|
45
|
Chairman of the Board of Directors and Chief Executive Officer
|
|
Charles J. Brown, III
|
66
|
Director, Chairman of Conflicts Committee and Member of Audit Committee
|
|
Eric D. Gadd
|
58
|
Director and Member of Audit and Conflicts Committees
|
|
Gary M. Sullivan, Jr.
|
67
|
Director, Chairman of Audit Committee and Member of Conflicts Committee
|
|
Mark B. Cox
|
55
|
Director
|
|
Assaf Ginzburg
|
38
|
Director, Executive Vice President and Chief Financial Officer
|
|
Frederec Green
|
48
|
Director and Executive Vice President
|
|
Harry P. (Pete) Daily
|
65
|
Executive Vice President
|
|
Donald N. Holmes
|
63
|
Executive Vice President
|
|
Andrew L. Schwarcz
|
46
|
Executive Vice President, General Counsel and Secretary
|
|
Kent B. Thomas
|
45
|
Executive Vice President
|
Ezra Uzi Yemin
has been the Chief Executive Officer and Chairman of the Board of our general partner since April 2012. Mr. Yemin has served as chief executive officer of Delek since June 2004 and as president and a director of Delek since April 2001. He was appointed to be the chairman of the board of directors of Delek in December 2012. Mr. Yemin also served as Delek's treasurer from April 2001 to November 2003 and as Delek's secretary from May 2001 to August 2005. The Board believes that, because he has worked for Delek since its founding, Mr. Yemin brings to the Board a thorough and complete understanding of our business, operations and operating environment, as well as that of Delek (the owner of approximately 62% of our units and the customer on whom the Partnership is most dependent). Mr. Yemin also brings to the Board substantial leadership, planning and industry experience.
Charles J. Brown, III
has been a member of the Board of our general partner since November 2012. Mr. Brown is a licensed attorney with more than 30 years of experience in the energy industry. Since July 2013, Mr. Brown has served as the executive vice president of Apex Clean Energy, Inc., an independent renewable energy company, where he manages legal and business development activities. Mr. Brown is currently the owner of, and since 2011 the chief advisor for, CRW Energy, a consulting firm focused in the international power and utility industries. From 2008 through 2011, Mr. Brown served as a partner in the energy department of McGuireWoods LLP, a large international law firm. Mr. Brown was appointed to the Board because of his experience in the energy industry, and as an attorney he provides the Board with valuable expertise in matters involving the financial, legal, regulatory and risk matters affecting the Partnership.
Eric D. Gadd
has been a member of the Board of our general partner since October 2013. Mr. Gadd is the founder and president of the consulting firm Awelon LLC, which is focused on expanding business development opportunities for both public and private companies in the energy sector. He has over 35 years of diverse experience in the energy industry including exploration and production field services, mid-stream, renewable energy, commodity trading and risk management, and mergers and acquisitions. Prior to forming his consulting firm, Mr. Gadd held various executive positions with multiple leading companies
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in the energy industry over a 25 year period. Mr. Gadd was appointed to the Board because of his extensive energy industry experience.
Gary M. Sullivan, Jr.
has been a member of the Board of our general partner since November 2012. Mr. Sullivan is a certified public accountant and has been an adjunct faculty member at Virginia Commonwealth University's School of Business since January 2012 where he teaches accounting. From 2009 to 2012, Mr. Sullivan was a private investor. From 1975 through 2009, Mr. Sullivan served in various roles with Deloitte & Touche LLP culminating in the role of senior client partner from 2004 through 2009 and was involved in such capacity with several public companies, including sponsors of master limited partnerships. Mr. Sullivan was appointed to the Board because the Board believed that his experience as a certified public accountant and partner with Deloitte & Touche, LLP provides the Board with valuable expertise in matters involving finance and accounting in general and master limited partnerships in particular.
Mark B. Cox
has been a member of the Board of our general partner since April 2012. Mr. Cox is currently Chief Financial Officer of Eco-Energy, Inc., an alternative energy company focused on the marketing, trading, transportation and blending of biofuels. He was an executive vice president of our general partner from April 2012 until March 2013 and of Delek from September 2009 until March 2013. Mr. Cox served as the chief financial officer of our general partner from April 2012 until January 2013 and as the chief financial officer of Delek from September 2009 until January 2013. From June 2007 until September 2009, Mr. Cox served as the senior vice president-treasurer and director of investor relations of Western Refining, Inc., a publicly traded refining company. Between 1994 and 2007, he was employed by Giant Industries, Inc., and served in various positions including Vice President, Executive Vice President, Treasurer, Chief Financial Officer and Assistant Secretary. Mr. Cox was appointed to the Board because his energy industry and financial experience provides the Board with valuable expertise in financial and accounting matters typically confronted by companies in our industry.
Assaf Ginzburg
has been the chief financial officer of our general partner and Delek since January 2013. Mr. Ginzburg has served as a director and executive vice president of our general partner since April 2012, as Delek's executive vice president since May 2009 and as a vice president of Delek since February 2005. Mr. Ginzburg has been a member of the Israel Institute of Certified Public Accountants since 2001. Mr. Ginzburg was instrumental in the successful completion of our initial public offering in November 2012, and he was appointed to the Board because his financial experience and knowledge of our and Delek's businesses provides the Board with valuable expertise into relevant business and financial and accounting matters.
Frederec Green
has been an executive vice president and a member of the board of our general partner since April 2012. Mr. Green has served as Delek's executive vice president since May 2009 and as the primary operational officer for Delek's refining operations since joining Delek in January 2005. From January 2004 until he joined Delek, Mr. Green operated Green Energy Advisors LLC, an independent consulting practice servicing commercial insurance carriers on petroleum refining and electrical matters. Mr. Green has over 25 years of experience in the refining industry ranging from crude oil and feedstock supply, through all aspects of managing a refining business to product trading, transportation and sales. Mr. Green was appointed to the Board because of his extensive energy industry experience and his in-depth knowledge of our and Delek's businesses and operations.
Pete Daily
has been an executive vice president of our general partner since April 2012. Mr. Daily has served as an executive vice president of Delek since November 2011 and as the primary operational officer for our Predecessor's operations since joining Delek in September 2006. Mr. Daily's duties include supervising the purchase and supply of crude oil for Delek's refineries and refined products for Delek's convenience stores, marketing the refined products produced by Delek's refineries and marketing Delek's supply of refined products in west Texas. Mr. Daily has over 30 years of industry experience in the energy logistics and marketing business.
Donald N. Holmes
has been an executive vice president of our general partner and Delek since August 2012. Mr. Holmes has served as the principal human resources officer of our general partner since its formation in April 2012 and has served in the same capacity with Delek since joining Delek in November 2011. Prior to joining Delek, Mr. Holmes served as senior vice president, human resources for Central Parking Corporation from January 2002 through September 2011.
Andrew L. Schwarcz
has been executive vice president, general counsel and secretary of our general partner since October 2012. Mr. Schwarcz joined Delek in a senior legal role in October 2007 and has served as Delek's vice president since April 2009.
Kent B. Thomas
has been an executive vice president of our general partner since October 2012. From April 2012 to October 2012, Mr. Thomas served as executive vice president, general counsel and secretary of our general partner. Mr. Thomas has served as Delek's executive vice president since November 2011 and as Delek's general counsel and secretary since joining Delek in August 2005.
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Board Leadership Structure
Mr. Yemin serves as Chairman of the Board. Our general partner has no policy with respect to the separation of the offices of Chairman and CEO. Rather, its policy is to let the Board make such a determination in the manner it deems most appropriate for the general partner and us at a given point in time. At this time, the Board believes that our general partner's Chief Executive Officer is best situated to serve as Chairman of the Board because he is the director most familiar with our business and industry. He is also the Chairman of the board of directors of Delek, which provides the Board and us with important interaction with, and access to, our most important client and majority unitholder. Mr. Yemin also brings to the Board and us the perspectives of our majority unitholder and the principal executive officer and chairman of the board of a publicly traded company. As such the Board feels that combining the roles of Chairman and CEO provides the Board with the individual who is most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy and facilitating the information flow between management and the Board and its committees, which are essential to effective governance of the Partnership. The Board met seven times in the year ended
December 31, 2013
with all directors in attendance at each meeting held during their tenure.
Executive Sessions
Independent directors and management have different perspectives and roles in strategy development. Our independent directors bring experience, oversight and expertise from outside the Partnership and industry, while our other board members bring experience and expertise specific to us and Delek. In addition, the independent directors are the sole members of our Audit and Conflicts Committees. The NYSE listing standards require our independent directors to meet at regularly scheduled executive sessions without management. Our independent directors conduct such executive sessions as frequently as necessary, but at minimum generally in connection with each quarterly meeting of the Audit Committee. As Chairman of the Audit Committee, Mr. Sullivan generally presides.
Communications with the Board of Directors of Our General Partner
Unitholders or other interested parties who wish to communicate with any of our directors, any committee chairperson or the Board may do so by writing to the director, committee chairperson or the Board in care of the Secretary of Delek Logistics Partners, LP at 7102 Commerce Way, Brentwood, Tennessee 37027. Any such communication received will be forwarded directly to the director to whom it is addressed. If the communication is addressed to the Board and no particular director is named, the communication will be forwarded, depending on the subject matter, to the appropriate committee chairperson or to all members of the Board.
Committees of the Board of Directors of Our General Partner
Audit Committee
The Board has a standing Audit Committee. The Audit Committee consists of Messrs. Sullivan (chairman), Brown and Gadd. Messrs. Sullivan and Brown joined the committee at its inception in November 2012 and Mr. Gadd joined the committee upon joining the Board in October 2013. The Audit Committee met four times during the year ended
December 31, 2013
.
The Board has determined that (i) each of Messrs. Sullivan, Brown and Gadd qualifies as independent under applicable SEC rules and regulations and the rules of the NYSE and (ii) Mr. Sullivan is an “audit committee financial expert” within the meaning of Item 407(d)(5) of Regulation S-K.
The purpose of the Audit Committee is to provide assistance to the Board in the oversight of (a) the quality and integrity of our financial statements; (b) the disclosure and financial reporting process, including our financial statements; (c) our internal controls and procedures for financial reporting; (d) the performance of our internal audit function and the independent registered public accounting firm employed by us for the purpose of preparing and issuing an audit report or related work; (e) the qualifications and independence of our independent registered public accounting firm; and (f) our compliance with policies under our Code of Business Conduct & Ethics and legal and regulatory requirements. These responsibilities are set forth in the Audit Committee’s charter, which is posted on our corporate website at www.DelekLogistics.com.
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Conflicts Committee
The Conflicts Committee consists of Messrs. Brown (chairman), Gadd and Sullivan. The Board has determined that each of Messrs. Brown, Gadd and Sullivan qualifies as independent under applicable SEC rules and regulations and the rules of the NYSE. Messrs. Brown and Sullivan joined the committee at its inception in November 2012 and Mr. Gadd joined the committee upon joining the Board in October 2013. The Conflicts Committee formally met seven times during the year ended
December 31, 2013
.
Our partnership agreement does not require that the Board seek approval from the Conflicts Committee to determine the resolution of any conflict of interest between us and Delek or any other person. However, pursuant to our Related Party Transactions Policy adopted by the Board in connection with the completion of our Offering, management of our general partner submits certain related party transactions, as defined by the policy, and which include material transactions between us and Delek, for review and approval or ratification by the Conflicts Committee or the disinterested members of the Board, acting in good faith. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, may not hold an ownership interest in the general partner or its affiliates other than common units or awards under any long-term incentive plan, equity compensation plan or similar plan implemented by the general partner or the partnership, and must meet the independence and experience standards established by the NYSE and the SEC to serve on an audit committee of a board of directors. With respect to any course of action taken, under our Partnership agreements, the Board shall be considered to have acted in good faith on matters approved by the Conflicts Committee in good faith and which the Board determines (i) are on terms no less favorable to us than those generally being provided to or available from unrelated third parties, or (ii) are fair and reasonable to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us). Any unitholder challenging any matter approved by the Conflicts Committee will have the burden of proving that the members of the Conflicts Committee did not act in good faith in accordance with the terms of our partnership agreement.
Director Nominations and Corporate Governance
As a limited partnership, we rely on an exemption from the provisions of the NYSE Listed Company Manual, which would otherwise require us to have a nominating and corporate governance committee. Our general partner is a limited liability company and its directors are not elected by its unitholders but by its members in their sole discretion. Accordingly, the Board believes it is unnecessary to have a nominating and corporate governance committee or a committee performing the functions of this committee. Candidates to serve on the Board are reviewed and selected in accordance with our general partner's Governance Guidelines, which are posted on our corporate website at www.DelekLogistics.com.
Compensation Decisions
Our general partner does not have a compensation committee. Our general partner has decided that a compensation committee is not necessary at this time, primarily because neither our general partner nor the Partnership has any direct employees to compensate. However, our Board believes it is important to promote the interests of the Partnership by providing to employees of the Partnership's affiliates and others who perform services for us or on our behalf incentive compensation awards for their service. Accordingly, the general partner adopted the Delek Logistics GP, LLC 2012 Long-Term Incentive Plan (the "LTIP"). Due to the fact that several of the members of the Board perform services on our behalf in their roles as executive officers of Delek, the LTIP is fully administered by the Conflicts Committee. The disinterested members of the full Board may also grant awards and the Conflicts Committee may delegate to, and has delegated in the past, to an executive officer of the general partner the authority to issue awards to non-Section 16 officers of the general partner. A compensation consultant was not used in the formulation of our compensation framework, objectives and philosophy. For a further discussion on the compensation practices of the general partner see "Item 11—Executive Compensation."
Governance Guidelines, Code of Business Conduct & Ethics and Committee Charters
The Governance Guidelines of the Board of Directors of our general partner, the charter of the Audit Committee of our general partner and our Code of Business Conduct & Ethics covering all employees, including our principal executive officer, principal financial officer, principal accounting officer and controllers, are available on our website, www.DelekLogistics.com under the "About Us - Corporate Governance" caption. A copy of any of these documents will be mailed upon request made to Investor Relations, Delek Logistics Partners, LP, or ir@deleklogistics.com. We intend to disclose any amendments to or waivers of the Code of Business Conduct & Ethics on behalf of our Chief Executive Officer, Chief Financial Officer and persons performing similar functions on our website, at www.DelekLogistics.com, under the “Investor Relations” caption, promptly following the date of any such amendment or waiver.
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SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act and regulations of the SEC thereunder require the executive officers and directors of our general partner and persons who own more than ten percent of our common units, as well as certain affiliates of such persons, to file initial reports of ownership of our common units and changes in their ownership with the SEC. Executive officers, directors and persons owning more than ten percent of our common units are required by SEC regulations to furnish us with copies of all Section 16(a) reports they file.
Based solely on our review of the copies of such reports received by us and written representations that no other reports were required for or by those persons, we believe that, during the year ended
December 31, 2013
all filing requirements applicable to the executive officers and directors of our general partner and owners of more than ten percent of our common units were met.
ITEM 11.
EXECUTIVE COMPENSATION
Neither we nor our general partner directly employs any of the persons responsible for managing our business. All of our general partner's executive officers and other personnel necessary for our business to function are employees of Delek.
Compensation Discussion and Analysis
This Compensation Discussion and Analysis (“CD&A”) discusses the principles underlying our general partner's compensation programs and the key executive compensation decisions that were made for
2013
. It also explains the most important factors relevant to such decisions. This CD&A provides context and background for the compensation earned and awarded to the individuals named in the Summary Compensation Table below. These individuals may be referred to as our named executive officers or “NEOs” herein. Because we did not compensate any of our executive officers in
2013
, our NEOs for
2013
are limited to the individuals who served as our principal executive officer and principal financial officer during
2013
.
Overview - Compensation Decisions and Allocation of Compensation Expenses
Our general partner does not have a compensation committee. Our general partner does not feel that a compensation committee is necessary at this time, primarily because neither our general partner nor the Partnership has any direct employees to compensate. However, our Board believes it is important to promote the interests of the Partnership and the general partner by providing to employees of the Partnership's affiliates and others who perform services for us or on our behalf incentive compensation awards for their service. Accordingly, pursuant to our partnership agreement, the general partner is allowed to and has adopted the LTIP. Due to the fact that several of the members of the Board perform services on our behalf in their roles as executive officers of Delek, the LTIP is fully administered by the Conflicts Committee. The disinterested members of the Board may also grant awards and the Conflicts Committee may delegate to, and has delegated in the past, to an executive officer of the general partner the authority to issue awards to non-Section 16 officers of the general partner.
Under the terms of the Omnibus Agreement, we pay an annual administrative fee of $3.3 million per year to Delek for the provision of general and administrative services. The general and administrative services covered by the annual administrative fee include, without limitation, executive management services of Delek employees who devote less than 50% of their time to our business, financial and administrative services, information technology services, legal services, health, safety and environmental services, human resources services and insurance administration. No service covered by the administrative fee is assigned any particular value individually. Additionally, the Omnibus Agreement requires us to reimburse Delek directly for a proportionate amount of the salary and employee benefits costs of Delek employees who devote more than 50% of their time to our business and affairs.
None of our NEOs devoted more than 50% of his total business time to our business and affairs in
2013
. No service covered by the administrative fee is assigned any particular value individually. Although our NEOs provide services to both Delek and us, no portion of the administrative fee is specifically allocated to services provided by our NEOs to us. Instead, the administrative fee covers all centralized services provided to us by Delek, and we have not reimbursed Delek for the cost
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of such services. Except for awards under the LTIP, Delek has the ultimate decision-making authority with respect to the compensation of our NEOs.
Compensation Objectives and Philosophy
Overview
In
2013
, because neither we nor our general partner employed directly any of our NEOs and because our NEOs are compensated by Delek to manage our business and affairs, we did not provide traditional fixed or discretionary compensation (e.g. salary and bonus) to our NEOs.
However, we believe that our NEOs should have an ongoing stake in our success, that their interests should be aligned with those of our unitholders and that the best interests of our unitholders will be most effectively advanced by enabling our NEOs who are responsible for our management, growth and success to receive compensation in the form of long-term incentive awards. Accordingly, our executive compensation program consists of a single element: long-term incentives in the form of awards under the LTIP, which was adopted in connection with the Offering in 2012 and is administered by the Conflicts Committee. The Conflicts Committee’s decisions with respect to the amount of awards made under the LTIP to our NEOs are governed by the following objectives:
|
•
|
to motivate and retain our general partner's key executives;
|
|
•
|
to align the long-term economic interests of our general partner's executives with those of our unitholders; and
|
|
•
|
to reward excellence and performance by our general partner's executives that increases the value of our units.
|
2012 Long-Term Incentive Plan
Awards may be made under the LTIP to officers, directors and employees of Delek, our general partner or its affiliates, as well as any consultants or other individuals who perform services for us.
Following the completion of the initial public offering on December 10, 2012, the Conflicts Committee granted awards under the LTIP to our NEOs. Mr. Yemin assisted the Conflicts Committee in determining the number and certain terms of these awards. Each of our NEOs received a grant of phantom units that vests ratably every six months beginning June 10, 2013 through December 10, 2017. These phantom units are accompanied by distribution equivalent rights that provide for a lump sum amount paid in cash on the vesting date that is equal to the accrued distributions from the grant date of the phantom units through the vesting date. No awards were made under the LTIP in 2013.
Pursuant to the terms of the LTIP, upon the occurrence of an Exchange Transaction (as defined in the LTIP, and generally including a merger, consolidation, acquisition, reorganization or similar extraordinary transaction), the Board may, in its discretion, accelerate the vesting of the phantom units, adjust the terms of any outstanding phantom units, or, in the event the Exchange Transaction in which our unitholders receive equity of another entity, provide for the conversion of the phantom units into comparable awards for such entity's equity. By providing the potential for immediate value to our NEOs in connection with an Exchange Transaction, this provision aligns our NEOs' interests with those of our unitholders and incentivizes our NEOs to work to maximize the value of our units in the event such a transaction were to occur. For additional detail regarding the amount of compensation our NEOs may be entitled to in the event of their termination or a change-in-control, see “—Potential Payments Upon Termination or Change-In-Control.”
General Partner Membership Interest Awards
In March 2013, the board of directors of Delek approved awards of membership interests in our general partner ("GP Membership Interests") to each of Messrs. Yemin and Ginzburg. The Delek board determined that, while the phantom unit awards under the LTIP in 2012 to Messrs. Yemin and Ginzburg aligned their interests with holders of units representing limited partner interests, awards of GP Membership Interests would also align the executives' incentives with holders of units representing general partner interests. As such, the Delek board granted Messrs. Yemin and Ginzburg awards of 1.0% and 0.2% GP Membership Interests, respectively. In connection with the vesting of these GP Membership Interest awards in June 2013, Messrs. Yemin and Ginzburg forfeited 4,898 and 980 unvested phantom units, respectively, such that each executive’s aggregate equity interest in Delek Logistics remained approximately the same following the grant of GP
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Membership Interests. Further, the Delek board of directors awarded Mr. Yemin an additional 4.0% GP Membership Interest in December 2013 in connection with Mr. Yemin's execution of his current employment agreement with Delek.
As members of our general partner, Messrs. Yemin and Ginzburg will participate in its future profits and losses from
operations, distributions from operations and liquidation value. Our general partner is entitled to distributions in respect of its 2.0% general partner interest and its incentive distribution rights in the Partnership. Any distributions payable by our general partner to its members while GP Membership Interests are unvested will be paid in arrears upon vesting of such interest. The incentive distribution rights are tied directly to our performance and are subordinate to our commitment to our limited partners. All GP Membership Interests are subject to restrictions on transfer under our general partner's limited liability company agreement. In particular, the GP Membership Interests are subject to call, put, drag-along and tag-along rights.
Acceleration of Certain Yemin Phantom Units
In connection with the approval of Mr. Yemin's 2013 employment agreement with Delek, the Conflicts Committee approved, upon the recommendation of the disinterested members of the Delek board and contingent upon Mr. Yemin’s execution of the 2013 agreement, the acceleration of 97,955 phantom units granted to Mr. Yemin in 2012 under the LTIP. These phantom units had been scheduled to vest ratably every six months through December 10, 2017. These 97,955 phantom units vested on December 10, 2013, and the 97,952 phantom units that remain unvested after December 10, 2013 will continue vest ratably every six months through December 10, 2017. The Conflicts Committee believes that the acceleration of these awards was appropriate to induce Mr. Yemin to continue his employment with Delek and reward excellence and performance by him that the Conflicts Committee believes have increased the value of our units.
Compensation Consultants
Our general partner does not have a compensation committee, and its Board did not retain a compensation consultant in 2013.
Perquisites
Our general partner does not provide any fringe benefits or perquisites to our NEOs.
Unit Ownership Requirements
Our general partner does not have express unit ownership requirements.
Prohibition Against Speculative Transactions
Our general partner's Code of Business Conduct & Ethics, which applies to all executive officers and directors of our general partner, prohibits speculative transactions in our units such as short sales, puts, calls or other similar options to buy or sell our units in an effort to hedge certain economic risks or otherwise.
Guidelines for Trades by Insiders
We maintain policies that govern trading in our units by officers and directors required to report under Section 16 of the Exchange Act, as well as certain other employees who may have regular access to material non-public information about us. These policies include pre-approval requirements for all trades and periodic trading “black-out” periods designed with reference to our quarterly financial reporting schedule. We also require pre-approval of all trading plans adopted pursuant to Rule 10b5-1 promulgated under the Exchange Act. To mitigate the potential for abuse, no trades are allowed under a trading plan within 30 days after adoption. In addition, we discourage termination or amendment of trading plans by prohibiting trades under new or amended plans within 90 days following a plan termination or amendment.
100
Compensation Committee Report
The members of the Conflicts Committee have reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Conflicts Committee recommended to the Board of our general partner that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
The members of the Conflicts Committee have submitted this Report to the Board of Directors as of February 28, 2014:
Charles J. Brown, III
Eric D. Gadd
Gary M. Sullivan, Jr.
2013
Summary Compensation Table
The Summary Compensation Table below summarizes the compensation for the fiscal year ended
December 31, 2013
(and the prior fiscal year) for our general partner's principal executive officer (Mr. Yemin), our general partner's current principal financial officer (Mr. Ginzburg) and our general partner's former principal financial officer (Mr. Cox). We refer to these individuals collectively herein as our “named executive officers” or “NEOs.”
|
(a)
|
(b)
|
(c)
|
(d)
|
(e)
|
(f)
|
(i)
|
(j)
|
|
Name and Principal Position
|
Fiscal Year
|
Salary
($)
|
Bonus
($)
|
Unit Awards
($)
|
Option Awards
($)
|
All Other Compensation
($)
|
Total
($)
|
|
Ezra Uzi Yemin
Chief Executive Officer
|
2013
|
0
|
0
|
0
|
0
|
0
|
0
|
|
2012
|
0
|
0
|
5,546,600
|
0
|
0
|
5,546,600
|
|
|
Assaf Ginzburg*
Executive Vice President and Chief Financial Officer
|
2013
|
0
|
0
|
0
|
0
|
0
|
0
|
|
2012
|
0
|
0
|
1,132,500
|
0
|
0
|
1,132,500
|
|
|
Mark B. Cox*
Former Executive Vice President and Chief Financial Officer
|
2013
|
0
|
0
|
0
|
0
|
0
|
0
|
|
2012
|
0
|
0
|
566,250
|
0
|
0
|
566,250
|
|
|
*
|
Mr. Cox's service as Delek's and our general partner's Chief Financial Officer ended, and Mr. Ginzburg's service as Chief Financial Officer began, on January 18, 2013. Mr. Cox's employment with Delek ended on March 31, 2013.
|
Grants of Plan Based Awards in
2013
Because each of our NEOs continued to benefit from significant plan-based equity awards granted in prior years, none of our NEOs were granted plan-based equity awards during
2013
.
101
Outstanding Equity Awards at
December 31, 2013
The following table provides information regarding the number of outstanding equity awards held by our NEOs at
December 31, 2013
.
|
Option Awards
|
Unit Awards
|
|||||
|
Name
|
Number of Securities Underlying Unexercised Options Exercisable
|
Number of Securities Underlying Unexercised Options Unexercisable
|
Option Exercise Price
|
Option Expiration Date
|
Number of Units That Have Not Vested (1)
|
Market Value of Units That Have Not Vested (2)
|
|
Ezra Uzi Yemin
|
—
|
—
|
n/a
|
n/a
|
97,952
|
$3,100,181
|
|
Mark B. Cox
|
—
|
—
|
n/a
|
n/a
|
0
|
$0
|
|
Assaf Ginzburg
|
—
|
—
|
n/a
|
n/a
|
40,000
|
$1,266,000
|
|
(1)
|
All awards in this column are phantom units which vest ratably every six months beginning June 10, 2014 through December 10, 2017.
|
|
(2)
|
Amounts
in this column are based upon a fair market value of
$31.65
per unit on
December 31, 2013
.
|
Option Exercises and Stock Vested in
2013
The following table provides information about the vesting of phantom units for our NEOs during fiscal year
2013
.
|
Option Awards
|
Stock Awards
|
|||||
|
Name
|
Number of Shares Acquired on Exercise
|
Value Realized on Exercise
|
Number of Shares Acquired on Vesting
|
Value Realized on Vesting (1)
|
||
|
Ezra Uzi Yemin
|
—
|
n/a
|
142,033
|
|
(2)
|
$4,704,229
|
|
Mark B. Cox
|
—
|
n/a
|
—
|
|
n/a
|
|
|
Assaf Ginzburg
|
—
|
n/a
|
9,020
|
|
(3)
|
$303,995
|
|
(1)
|
The values in this column are based upon the $34.75 and $32.86 fair market values of our common units on June 10, 2013 and December 10, 2013, respectively.
|
|
(2)
|
Consists
of 19,590 and 122,443 phantom units that vested on June 10, 2013 and December 10, 2013, respectively.
|
|
(3)
|
Consists
of 4,020 and 5,000 phantom units that vested on June 10, 2013 and December 10, 2013, respectively.
|
Potential Payments Upon Termination or Change-In-Control
The following table discloses the estimated payments and benefits that would be provided to each of our NEOs, assuming that each of the triggering events relating to termination of employment or change in control described in their respective employment agreements and the LTIP took place on
December 31, 2013
and their last day of employment with our general partner or its affiliates was
December 31, 2013
. Due to a number of factors that affect the nature and amount of any benefits provided upon the events discussed below, any actual amounts paid or distributed may differ. Factors that could affect these amounts include the timing during the year of any such event and our stock price.
|
Name
|
Termination of Employment
|
Change-In-Control (1)
|
||
|
Ezra Uzi Yemin
|
—
|
$3,100,181
|
(2)
|
|
|
Mark B. Cox
|
—
|
—
|
|
|
|
Assaf Ginzburg
|
—
|
$1,266,000
|
(3)
|
|
|
(1)
|
The numbers in the “Change-In-Control” column assume that an “exchange transaction” (as described below) occurred on
December 31, 2013
and, as a result, the Board of Directors of our general partner decided that all outstanding phantom units should become fully vested and participate in the transaction value of the units covered by the award (e.g., by exercise or cash out).
|
|
(2)
|
Consists
of the value of 97,952 phantom units.
|
|
(3)
|
Consists
of the value of 40,000 phantom units.
|
102
2012 Long-Term Incentive Plan
Under the LTIP and the applicable award agreements, phantom units that have not vested at the time the participant’s employment with our general partner or its affiliates terminates will generally be immediately forfeited unless the Board determines otherwise.
In the event of an Exchange Transaction, defined generally under the LTIP to include a merger, consolidation, acquisition or disposition of stock, separation, reorganization, liquidation or other similar event or transaction designated by the Board in which our unitholders receive cash, stock or other property in exchange for or in connection with their units, our NEOs may be entitled, at the discretion of the Board, to the accelerated vesting of phantom units awarded under the LTIP. The LTIP and applicable awards provide that the Board may, in its discretion, (i) accelerate the vesting of the phantom units, (ii) make other adjustments to the terms of the phantom units, or (iii) in the event the exchange transaction involves the receipt of equity of another entity in exchange for units, convert the phantom units into comparable awards relating to such entity's equity. The “Change-In-Control” column in the “Potential Payments Upon Termination or Change-In-Control” table above illustrates the value of phantom units under the LTIP assuming that an exchange transaction occurred on
December 31, 2013
and the Board elected to accelerate all of the phantom units held by our NEOs.
Compensation of Directors in
2013
The following table sets forth a summary of the compensation we paid to the members of the Board for service during
2013
.
|
DIRECTOR COMPENSATION
|
|||||||
|
Name (1)
|
Fees Earned or Paid in Cash ($)(2)
|
Stock Awards ($)(3)
|
Option Awards ($)
|
All Other Compensation ($)(4)
|
Total ($)
|
||
|
Charles J. Brown, III
|
55,000
|
86,875
|
|
(5)
|
—
|
705
|
142,580
|
|
Mark B. Cox
|
31,000
|
—
|
|
—
|
—
|
31,000
|
|
|
Eric D. Gadd
|
10,622
|
82,150
|
|
(6)
|
—
|
—
|
92,772
|
|
Gary M. Sullivan, Jr.
|
60,500
|
86,875
|
|
(5)
|
—
|
705
|
148,080
|
|
(1)
|
Because they are officers and employees of Delek or its subsidiaries, Messrs. Yemin, Ginzburg and Green did not receive any compensation for their service as directors in 2013. In addition, Mr. Cox did not receive any such compensation during his tenure as an officer and employee of Delek or its subsidiaries.
|
|
(2)
|
This column reports the amount of cash compensation earned in
2013
for Board and committee service.
|
|
(3)
|
Amounts in this column represent the aggregate grant date fair value computed in accordance with FASB ASC Topic 718 for financial statement reporting purposes. Assumptions used in the calculation of this amount for the
2013
fiscal year are included in
Note 12
to our audited financial statements for the
2013
fiscal year included in this Annual Report on Form 10-K.
|
|
(4)
|
Consists of distribution equivalents paid upon vested phantom units.
|
|
(5)
|
The grant date fair value of $34.75 per unit is equal to the NYSE closing price of our common units on the grant date. Each of Messrs. Brown and Sullivan held 4,250 outstanding phantom units at
December 31, 2013
.
|
|
(6)
|
The
grant date fair value of $32.86 per unit is equal to the NYSE closing price of our common units on the grant date. Mr. Gadd held 2,500 outstanding phantom units at
December 31, 2013
.
|
Officers and employees of Delek or its subsidiaries do not receive additional compensation for service on the Board or its committees. The compensation framework for the Board's other directors (Messrs. Brown, Gadd and Sullivan and, following the termination of his employment with Delek on March 31, 2013, Mr. Cox) (the "Compensated Directors") was determined by the Board. We pay the Compensated Directors a cash retainer of $8,750 per quarter and award the Compensated Directors 2,500 phantom units per year with distribution equivalent rights. We pay the Audit Committee chairman an additional cash retainer of $2,500 per quarter and the Conflicts Committee chairman an additional cash retainer of $1,250 per quarter. In addition, each such director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the Board and committee meetings. We pay meeting fees to the Compensated Directors in the amount of $1,500 for each in-person Board meeting, $1,000 for each in-person committee meeting and half the fee otherwise due for meetings attended other than in person. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our partnership agreement. See the table below for a summary of the cash compensation to the Compensated Directors in
2013
.
103
|
Director Annual Retainer and Fees (1)
|
||
|
Board of Directors Quarterly Retainer (2)
|
$8,750 quarterly
|
|
|
Annual Retainer for Audit Committee Chair
|
$10,000
|
|
|
Annual Retainer for Conflicts Committee Chair
|
$5,000
|
|
|
Board and Committee Meeting Fees:
|
||
|
In-person board meeting
|
$1,500 per meeting
|
|
|
In-person committee meeting
|
$1,000 per meeting
|
|
|
Telephonic board meeting
|
$750 per meeting
|
|
|
Telephonic committee meeting
|
$500 per meeting
|
|
|
(1)
|
In addition to the retainers set forth above, we reimburse our non-employee directors for travel and lodging expenses that they incur in connection with attending meetings of the Board or its committees.
|
|
(2)
|
The
quarterly retainer of $8,750 is payable in cash. Each of our three independent directors were also awarded 2,500 phantom units in
2013
. Holders of phantom units also receive distribution equivalent rights for each phantom unit, providing for a lump sum cash amount equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date.
|
Compensation Committee Interlocks and Insider Participation
Messrs. Brown, Gadd and Sullivan served on the Conflicts Committee during
2013
and Mr. Yemin assisted the committee with respect to compensation matters. There are no interlocking relationships requiring disclosure pursuant to Item 407(e)(4)(iii) of Regulation S-K.
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth, as of
February 18, 2014
, (i) the beneficial ownership of our units representing limited partnership interests and Common Stock of Delek US Holdings, Inc. by all directors and director nominees of our general partner, our NEOs and all of our executive officers as a group and (ii) the beneficial ownership of our units representing limited partnership interests by each person known by us to own more than five percent of such units or more than five percent of any class of our units. The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. Unless otherwise indicated below, each person or entity has an address in care of our principal executive offices at 7102 Commerce Way, Brentwood, Tennessee 37027.
104
|
Delek Logistics Partners, LP
|
Delek US Holdings, Inc.
|
|||||||||
|
Name of Beneficial Owner
(1)
|
Amount, Nature and Percentage of Beneficial Ownership of Common Units (2)
|
Amount, Nature and Percentage of Beneficial Ownership of Subordinated Units
(2)
|
Amount, Nature and Percentage of Beneficial Ownership of General Partner Units
(2)
|
Amount and Nature of Beneficial Ownership of Common Stock
(2)
|
||||||
|
(#)
|
(%)
|
(#)
|
(%)
|
(#)
|
(%)
|
(#)
(3)
|
(%)
|
|||
|
Delek US Holdings, Inc.
(4)
|
2,799,258
|
23.0
|
11,999,258
|
100.0
|
492,893
|
100.0
|
n/a
|
|
n/a
|
|
|
Piper Jaffray Companies
(5)
|
1,370,785
|
11.3
|
—
|
—
|
—
|
—
|
n/a
|
|
n/a
|
|
|
Goldman Sachs Asset Management
(6)
|
1,190,563
|
9.8
|
—
|
—
|
—
|
—
|
n/a
|
|
n/a
|
|
|
Clearbridge Investments, LLC
(7)
|
803,865
|
6.6
|
—
|
—
|
—
|
—
|
n/a
|
|
n/a
|
|
|
Ezra Uzi Yemin
(8)
|
146,351
|
|
1.2
|
—
|
—
|
—
|
—
|
411,348
|
|
*
|
|
Charles Brown
|
750
|
|
*
|
—
|
—
|
—
|
—
|
0
|
|
*
|
|
Mark B. Cox
|
25,000
|
|
*
|
—
|
—
|
—
|
—
|
0
|
|
*
|
|
Eric Gadd
|
—
|
|
*
|
—
|
—
|
—
|
—
|
0
|
|
*
|
|
Gary Sullivan
|
1,950
|
|
*
|
—
|
—
|
—
|
—
|
0
|
|
*
|
|
Assaf Ginzburg
(9)
|
34,020
|
|
*
|
—
|
—
|
—
|
—
|
34,406
|
|
*
|
|
Frederec Green
(10)
|
34,020
|
|
*
|
—
|
—
|
—
|
—
|
71,574
|
|
*
|
|
All directors, all director nominees, all NEOs and all executive officers as a group (11 persons)
|
267,841
|
|
2.2
|
—
|
—
|
—
|
—
|
592,190
|
|
1.0
|
|
*
|
Less than 1% of our issued and outstanding common units or issued and outstanding shares of Delek US Holdings, Inc. Common Stock, as applicable.
|
|
(1)
|
Unless otherwise indicated, the address for all beneficial owners is 7102 Commerce Way, Brentwood, Tennessee 37027.
|
|
(2)
|
For purposes of this table, a person is deemed to have “beneficial ownership” of any securities when such person has the right to acquire them within 60 days after
February 18, 2014
. The percentage of our units beneficially owned is based on a total of 12,152,498 common units, 11,999,258 subordinated units representing limited partner interests and 492,893 general partner units issued and outstanding on
February 18, 2014
. The percentage ownership of Delek US Holdings, Inc. Common Stock is based on a total of
59,234,569
shares issued and outstanding shares on
February 18, 2014
(excluding securities held by or for the account of the registrant or its subsidiaries). For purposes of computing the percentage of outstanding securities held by each person named above, any securities which such person has the right to acquire within 60 days after
February 18, 2014
are deemed to be outstanding but are not deemed to be outstanding for the purpose of computing the percentage ownership of any other person.
|
|
(3)
|
For non-qualified stock options (“NQSOs”) and restricted stock units (“RSUs”) under the Delek US Holdings, Inc. 2006 Long-Term Incentive Plan, we report shares equal to the number of NQSOs or RSUs that are vested or that will vest within 60 days of
February 18, 2014
. For stock appreciation rights (“SARs”) under the Delek US Holdings, Inc. 2006 Long-Term Incentive Plan, we report the shares that would be delivered upon exercise of SARs that are vested or that will vest within 60 days of
February 18, 2014
(which is calculated by multiplying the number of SARs by the difference between the
$29.36
fair market value of Delek US Holdings, Inc. Common Stock at
February 18, 2014
and the exercise price divided by
$29.36
).
|
|
(4)
|
Subsidiaries of Delek US Holdings, Inc. hold the common units, subordinated units and general partner units. Lion Oil Company and Delek Marketing & Supply, LLC directly hold 612,207 and 2,187,051 common units, respectively. Lion Oil Company and Delek Logistics GP, LLC directly hold all subordinated units and general partner units, respectively. Delek US Holdings, Inc. is the ultimate parent of each of these entities and may, therefore, be deemed to beneficially own the units held by each such entity. Delek US Holdings, Inc. files information with, or furnishes information to, the United States Securities and Exchange Commission (the "SEC") pursuant to the information requirements of the Securities Exchange Act of 1934, as amended.
|
|
(5)
|
According to a Schedule 13G/A filed with the SEC on February 12, 2014 by Piper Jaffray Companies, with an address of 800 Nicollet Mall, Suite 800, Minneapolis, Minnesota 55402. The Schedule 13G/A reports that Piper Jaffray Companies has sole voting and dispositive power with respect to the reported units.
|
|
(6)
|
According to a Schedule 13G/A filed with the SEC on February 13, 2014 by Goldman Sachs Asset Management, with an address of 200 West Street, New York, New York 10282. The Schedule 13G/A reports that Goldman Sachs Asset Management, L.P. and GS Investment Strategies, LLC share voting and dispositive power with respect to the reported units.
|
|
(7)
|
According to a Schedule 13G/A filed with the SEC on February 14, 2014 by Clearbridge Investments, LLC, with an address of 620 8th Avenue, New York, New York 10018. The Schedule 13G/A reports that Clearbridge Investments, LLC has sole voting and dispositive power with respect to the reported units.
|
|
(8)
|
30,000 of our units and 106,802 shares of Delek US Holdings, Inc. Common Stock are held of record by Yemin Investments, L.P., a limited partnership of which Mr. Yemin is the sole general partner.
|
|
(9)
|
Delek US Holdings, Inc. Common Stock includes 13,333 RSUs that will vest within 60 days of
February 18, 2014
.
|
|
(10)
|
Delek US Holdings, Inc. Common Stock includes 11,750 RSUs that will vest within 60 days of
February 18, 2014
.
|
105
EQUITY COMPENSATION PLAN INFORMATION
The following table provides certain information as of
December 31, 2013
regarding our general partner's equity compensation plans.
|
Plan Category
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights
|
Weighted-average exercise price of outstanding options, warrants and rights
|
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
|
|
(a)
|
(b)
|
(c)
|
|
|
Equity compensation plans approved by security holders
|
494,883
|
N/A
|
117,324
|
|
Equity compensation plans not approved by security holders
|
—
|
N/A
|
—
|
|
TOTAL
|
494,883
|
N/A
|
117,324
|
|
(a)
|
The amounts in column (a) of this table reflect only phantom units that have been granted under the LTIP. No Awards (as defined under the LTIP) have been made other than the phantom units, each of which represent rights to receive (upon vesting and payout) one common unit in the Partnership or an amount of cash equal to the fair market value of such unit. These phantom units vest pro-rata, semi-annually over five years from the date of grant.
|
|
(b)
|
Column
(b) of this table is not applicable because phantom units do not have an exercise price.
|
|
(c)
|
The
LTIP was adopted by the Delek Logistics GP, LLC in connection with the closing of our Offering and provides for the making of certain awards, including common units, restricted units, phantom units, unit appreciation rights and distribution equivalent rights. For information about the LTIP, which did not require approval by our limited partners, refer to Item 11 of this Annual Report on Form 10-K.
|
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
The information required by Item 407(a) of Regulation S-K is included in Item 10 "Directors, Executive Officers and Corporate Governance" above.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Approval Policy for Related Party Transactions
As of March 1, 2014, Delek owned 2,799,258 common units, 11,999,258 subordinated units, and 492,893 general partner units, as well as incentive distribution rights, which collectively represents a 62.0 percent ownership interest in the Partnership. Transactions with Delek and its affiliated entities are considered to be related party transactions because Delek and its affiliates, including our general partner, own more than 5% of our equity interests. In addition, Messrs. Yemin, Ginzburg, Green, Daily, Holmes and Thomas serve as executive officers of both Delek and our general partner.
Accordingly, whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. On November 6, 2012, in conjunction with the consummation of the Offering, the Board adopted a written related party transactions policy to document procedures pursuant to which “related party transactions” are reviewed, approved or ratified. Under our policy, a related party generally includes the directors and executive officers of our general partner and their immediate family members as well as individuals (and their immediate family members) and entities that are beneficial owners of more than 5% of our voting securities. The policy covers all transactions in which one of our related parties has a direct or indirect material interest, other than transactions generally available to all employees and transactions involving less than $5,000, when aggregated with all similar transactions, other than conflicts of interest the resolution of which is governed by our partnership agreement.
106
Our partnership agreement does not require that the Board seek approval from the Conflicts Committee to determine the resolution of any conflict of interest resulting from a related party transaction between us and Delek or any other related party. However, pursuant to our related party transactions policy, management of our general partner must assure that any related party transaction, which includes any transaction between us and Delek, will only be consummated or allowed to continue if the Conflicts Committee or the disinterested members of the Board, acting in good faith, approve or ratify such transaction. For a further discussion of our Conflicts Committee see, "Item 10—Directors, Executive Officers and Corporate Governance—Committees of the Board of Directors of our General Partner—Conflicts Committee". With respect to any course of action taken, the Board shall be considered to have acted in good faith on any matters approved by the Conflicts Committee in good faith and which the Board determines (i) are on terms no less favorable to us than those generally being provided to or available from unrelated third parties, or (ii) are fair and reasonable to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us). Any unitholder challenging any matter approved by the Conflicts Committee will have the burden of proving that the members of the Conflicts Committee did not act in good faith in accordance with the terms of our partnership agreement.
We expect that in determining whether to approve a related party transaction, the Conflicts Committee will consider whether the terms are fair to us, taking into account the totality of our relationships with the related party, whether the transaction is material to us, whether the terms are no less favorable to us than those generally being provided to or available from unrelated third parties and the structure of the transaction, as well as any other factors that the conflicts committee may deem appropriate.
Initial Public Offering and Related Structuring Transactions
On November 2, 2012 the Partnership's common units began trading on the New York Stock Exchange under the symbol "DKL." On November 7, 2012, we closed our Offering of
9,200,000
common units at a price of
$21.00
per unit, which included a
1,200,000
unit over-allotment option that was exercised in full by the underwriters. In connection with the Offering, all of our initial assets were contributed by Delek (including its subsidiaries Delek Marketing & Supply, LLC and Lion Oil Company) in a series of transactions in exchange for:
|
•
|
2,799,258
common units and
11,999,258
subordinated units, representing an approximate aggregate 62.4% interest, including the general partner interest, in DKL;
|
|
•
|
all of the incentive distribution rights;
|
|
•
|
489,766
general partner units, representing a 2% general partner interest; and
|
|
•
|
an aggregate cash distribution of
$231.3 million
.
|
Distributions and Payments to Delek and Our General Partner
Our partnership agreement generally requires us to make quarterly cash distributions of 98% of our "available cash" to limited partners, including Delek, and 2% to our general partner (assuming it makes any capital contributions necessary to maintain its 2% interest in us). In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, the general partner may be entitled to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level. During
2013
, we made distributions totaling
$129.6 million
to our unitholders.
Commercial Agreements, Omnibus Agreement and Operations and Management Services Agreement
In connection with the completion of the Offering, we entered into various long-term, fee-based commercial agreements with Delek under which we provide gathering, pipeline transportation, storage, wholesale marketing and products terminalling services to Delek, and Delek commits to minimum monthly throughput volumes of crude oil and refined products. These agreements are described in detail under the heading "Item 1—Business—Commercial Agreements—Commercial Agreements in Connection with the Offering," "—Commercial Agreements—Commercial Agreements in Connection with the Tyler Acquisition" and —Commercial Agreements—Other Agreements with Delek. The amounts paid under those agreements during
2013
are as follows:
|
•
|
Delek paid us approximately
$38.4 million
pursuant to the Lion Pipeline System pipeline and storage facilities agreement and the Memphis terminalling agreement in
2013
and
$0.5 million
for terminalling services at our Nashville, Tennessee terminal;
|
|
•
|
Delek paid us approximately
$9.0 million
pursuant to the East Texas Crude Logistics System pipeline and tankage agreement in
2013
;
|
|
•
|
Delek paid us approximately
$13.6 million
pursuant to the East Texas marketing agreement in
2013
;
|
|
•
|
Delek paid us approximately
$2.0 million
pursuant to the amended and restated services agreement for the Big Sandy terminal and pipeline in
2013
;
|
107
|
•
|
Delek paid us approximately
$7.5 million
pursuant to the Tyler Terminal and Tank Assets Throughput and Tankage Agreement in
2013
.
|
|
•
|
Delek paid us approximately
$0.2 million
pursuant to the North Little Rock terminalling services agreement.
|
For a discussion of a third party's involvement in certain of these agreements, see "Item 1Business—Commercial Agreements—El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement."
Pursuant to the terms of the Omnibus Agreement, we paid Delek approximately
$3.7 million
, which includes
$2.8 million
related to general and administrative services and
$0.9 million
related to insurance coverage. Delek paid us approximately
$0.9 million
pursuant to the Omnibus Agreement during
2013
as indemnification relative to the Paline Pipeline. Additionally, we were paid
$3.9 million
pursuant to the Omnibus Agreement in relation to expenses incurred in connection with the Magnolia and Macedonia crude oil releases that occurred in March and October 2013, respectively. We were also reimbursed
$0.8 million
for certain capital improvements pursuant to the terms of the Omnibus Agreement.
In connection with the operations and management services agreement, we paid Delek approximately
$5.9 million
in
2013
. On
July 26, 2013
, in connection with the Tyler Acquisition, the Partnership, our general partner and Delek Logistics Services Company terminated the operation and management services agreement. We continued to reimburse our general partner for the services it provides to us under our partnership agreement, under which we paid Delek approximately
$6.5 million
.
In addition to the agreements described above, we purchased finished product from Delek, totaling
$55.5 million
during the year ended
December 31, 2013
. We also purchased bulk biofuels totaling
$24.6 million
from Delek for sale and exchange at our Abilene and San Angelo, Texas terminals during the year ended
December 31, 2013
. In addition, we sold Renewable Identification Numbers in the amount of approximately
$6.2 million
to Delek during the year ended
December 31, 2013
.
The Omnibus Agreement and operations and management services agreements are described in greater detail under the heading "Item 1—Business—Commercial Agreements—Other Agreements with Delek."
On July 9, 2013, we amended and restated our senior secured revolving credit agreement, which we originally entered into on November 7, 2012, with Fifth Third Bank, as administrative agent, and a syndicate of lenders (the "Amended and Restated Credit Agreement"). The obligations under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of the Partnership's and its U.S. subsidiaries' tangible and intangible assets. Additionally, Delek Marketing provides a limited guaranty of the Partnership's obligations under the Amended and Restated Credit Agreement. Delek Marketing's guaranty is (i) limited to an amount equal to the principal amount, plus unpaid and accrued interest, of a promissory note made by Delek US in favor of Delek Marketing (the "Holdings Note") and (ii) secured by Delek Marketing's pledge of the Holdings Note to our lenders under the Amended and Restated Credit Agreement. As of December 31, 2013, the principal amount of the Holdings Note was $102.0 million, plus unpaid interest accrued since the issuance date. The Amended and Restated Credit Agreement, the guaranty and the transactions related to it are described in greater detail under the heading “Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cash Position and Indebtedness.”
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Audit fees of $881,861 and $665,877 paid for the services of Ernst & Young LLP during fiscal year
2013
and
2012
, respectively, include services related to the audits
of our consolidated financial statements and audit services provided in connection with our regulatory filings. Fees and expenses are for services in connection with the audit of our fiscal years ended
December 31, 2013
and
December 31, 2012
financial statements regardless of when the fees and expenses were paid.
The Audit Committee has considered and determined that the provision of non-audit services by our independent registered public accounting firm is compatible with maintaining auditor independence.
Pre-Approval Policies and Procedures.
In general, all engagements performed by our independent registered public accounting firm, whether for auditing or non-auditing services, must be pre-approved by the Audit Committee. During the year ended December 31, 2013, all of the services performed for us by Ernst & Young LLP were pre-approved by the Audit Committee.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Certain Documents Filed as Part of this Annual Report on Form 10-K:
|
1.
|
Financial Statements. The accompanying Index to Financial Statements and Schedule on page F-1 of this Annual Report on Form 10-K is provided in response to this item.
|
108
|
2.
|
List of Financial Statement Schedules. All schedules are omitted because the required information is either not present, not present in material amounts or included within the Consolidated Financial Statements.
|
|
3.
|
Exhibits - See below.
|
EXHIBIT INDEX
|
Exhibit No.
|
Description
|
||
|
3.1
|
Certificate of Limited Partnership of Delek Logistics Partners, LP (incorporated by reference to Exhibit 3.1 to the Partnership's Form S-1 (File No. 333-182631) filed on July 12, 2012).
|
||
|
3.2
|
First Amended and Restated Agreement of Limited Partnership of Delek Logistics Partners, LP, dated November 7, 2012 (incorporated by reference to Exhibit 3.1 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
3.3
|
Certificate of Formation of Delek Logistics GP, LLC (incorporated by reference to Exhibit 3.3 to the Partnership's Registration Statement on Form S-1 (File No. 333-182631) filed on July 12, 2012).
|
||
|
3.4
|
Third Amended and Restated Limited Liability Company Agreement of Delek Logistics GP, LLC, dated as of December 10, 2013 (incorporated by reference to Exhibit 3.1 to the Partnership’s Form 8-K filed on December 13, 2013).
|
||
|
10.1
|
Second Amended and Restated Omnibus Agreement, dated as of February 10, 2014, by and among Delek US Holdings, Inc., Lion Oil Company, Delek Logistics Operating, LLC, Delek Marketing & Supply, LP, Delek Refining, Ltd., Delek Logistics Partners, LP, Paline Pipeline Company, LLC, SALA Gathering Systems, LLC, Magnolia Pipeline Company, LLC, El Dorado Pipeline Company, LLC, Delek Crude Logistics, LLC, Delek Marketing-Big Sandy, LLC and Delek Logistics GP, LLC (incorporated by reference to Exhibit 10.2 to the Partnership’s Form 8-K filed on February 14, 2014).
|
||
|
10.2
|
Operation and Management Services Agreement, dated November 7, 2012, by and among Delek Logistics Services Company, Delek Logistics Partners, LP and Delek Logistics GP, LLC.
(incorporated by reference to Exhibit 10.2 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.3
|
Amended and Restated Credit Agreement, dated July 9, 2013, by and among Delek Logistics Partners, LP, Delek Logistics Operating, LLC, Delek Marketing GP, LLC, Delek Marketing & Supply, LP, Delek Crude Logistics, LLC, Delek Marketing-Big Sandy, LLC, Magnolia Pipeline Company, LLC, El Dorado Pipeline Company, LLC, SALA Gathering Systems, LLC, and Paline Pipeline Company, LLC and Fifth Third Bank, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on July 12, 2013).
|
||
|
10.4
|
Contribution, Conveyance and Assumption Agreement, dated November 7, 2012, by and among Delek Logistics Partners, LP, Delek Logistics GP, LLC, Delek Logistics Operating, LLC, Delek Crude Logistics, LLC, Delek US Holdings, Inc., Delek Marketing & Supply, LLC, Delek Marketing and Supply, LP, Lion Oil Company and Delek Logistics Services Company (incorporated by reference to Exhibit 10.4 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.5
|
*
|
Delek Logistics GP, LLC 2012 Long-Term Incentive Plan, dated November 7, 2012 (incorporated by reference to Exhibit 10.5 to the Partnership's Form 8-K filed on November 7, 2012).
|
|
|
10.6
|
++
|
Marketing Agreement, dated November 7, 2012, by and between Delek Refining, Ltd. and Delek Marketing & Supply, LP (incorporated by reference to Exhibit 10.6 to the Partnership's Form 8-K filed on November 7, 2012).
|
|
|
10.7
|
Pipelines and Tankage Agreement (East Texas Crude Logistics System), dated November 7, 2012, by and between Delek Refining, Ltd. and Delek Crude Logistics, LLC (incorporated by reference to Exhibit 10.7 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.8
|
Terminalling Services Agreement (Big Sandy Terminal), dated November 7, 2012, by and between Delek Refining, Ltd. and Delek Marketing-Big Sandy, LLC (incorporated by reference to Exhibit 10.8 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
109
|
10.9
|
Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline), dated July 25, 2013, by and between Delek Refining, Ltd. and Delek Marketing-Big Sandy, LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K/A filed on July 31, 2013).
|
||
|
10.10
|
Pipelines and Storage Facilities Agreement, dated November 7, 2012, by and among Lion Oil Company, Delek Logistics Partners, LP, SALA Gathering Systems, LLC, El Dorado Pipeline Company, LLC, Magnolia Pipeline Company, LLC and J. Aron & Company (incorporated by reference to Exhibit 10.9 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.11
|
Terminalling Services Agreement (Memphis Terminal), dated November 7, 2012, by and between Lion Oil Company, Delek Logistics Operating, LLC and J. Aron & Company (incorporated by reference to Exhibit 10.10 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.12
|
*
|
Form of Director Phantom Unit Award (incorporated by reference to Exhibit 10.6 to the Partnership's Amendment No. 3 to Registration Statement on Form S-1 (File No. 333-182631), filed on October 16, 2012).
|
|
|
10.13
|
*
|
Form of Employee Phantom Unit Award (incorporated by reference to Exhibit 10.7 to the Partnership's Amendment No. 3 to Registration Statement on Form S-1 (File No. 333-182631), filed on October 16, 2012).
|
|
|
10.14
|
*
|
Form of Indemnification Agreement for Directors and Officers of Delek Logistics GP, LLC (incorporated by reference to Exhibit 10.13 to the Partnership's Amendment No. 4 to Registration Statement on Form S-1 (File No. 333-182631), filed on October 24, 2012).
|
|
|
10.15
|
Asset Purchase Agreement, dated July 26, 2013, by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on August 1, 2013).
|
||
|
10.16
|
Tyler Throughput and Tankage Agreement, dated July 26, 2013 by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.3 to the Partnership’s Form 8-K filed on August 1, 2013).
|
||
|
10.17
|
Tyler Lease and Access Agreement, dated July 26, 2013, by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.4 to the Partnership’s Form 8-K filed on August 1, 2013).
|
||
|
10.18
|
Tyler Site Services Agreement, dated July 26, 2013, by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.5 to the Partnership’s Form 8-K filed on August 1, 2013).
|
||
|
10.19
|
Asset Purchase Agreement, dated as of February 10, 2014, between Lion Oil Company and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on February 14, 2014).
|
||
|
10.20
|
El Dorado Throughput and Tankage Agreement, dated as of February 10, 2014, between Lion Oil Company and Delek Logistics Operating, LLC, and for limited purposes, J. Aron & Company (incorporated by reference to Exhibit 10.3 to the Partnership’s Form 8-K filed on February 14, 2014).
|
||
|
10.21
|
El Dorado Lease and Access Agreement, dated as of February 10, 2014, between Lion Oil Company and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.4 to the Partnership’s Form 8-K filed on February 14, 2014).
|
||
|
10.22
|
El Dorado Site Services Agreement, dated as of February 10, 2014, between Lion Oil Company and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.5 to the Partnership’s Form 8-K filed on February 14, 2014).
|
||
|
21.1
|
#
|
Subsidiaries of Registrant.
|
|
|
23.1
|
#
|
Consent of Independent Registered Public Accounting Firm (Ernst & Young LLP).
|
|
|
24.1
|
#
|
Power of Attorney.
|
|
|
31.1
|
#
|
Certification of Delek Logistics GP, LLC's Chief Executive Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act of 1934, as amended.
|
|
|
31.2
|
#
|
Certification of Delek Logistics GP, LLC's Chief Financial Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act of 1934, as amended.
|
|
|
32.1
|
#
|
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
32.2
|
#
|
Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
110
|
101
|
^
|
The following materials from Delek Logistics Partners, LP Annual Report on Form 10-K for the annual period ended December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of December 31, 2013 and 2012; (ii) Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2013, 2012 and 2011; (iii) Consolidated Statements of Changes in Partners’ Equity for the years ended December 31, 2013, 2012 and 2011; (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; and (v) Notes to Consolidated Financial Statements.
|
|
|
*
|
Management contract or compensatory plan or arrangement.
|
||
|
#
|
Filed herewith.
|
||
|
++
|
Confidential treatment has been requested and granted with respect to certain portions of this exhibit pursuant to Rule 24b-2 of the Securities Exchange Act of 1934. Omitted portions have been filed separately with the Securities and Exchange Commission.
|
||
|
^
|
Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files in Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.
|
||
111
Delek Logistics Partners, LP
Consolidated Financial Statements
As of
December 31, 2013
and
2012
and
For Each of the Three Years Ended
December 31, 2013
,
2012
and
2011
INDEX TO FINANCIAL STATEMENTS
|
Audited Financial Statements:
|
|
All other financial schedules are not required under related instructions, or are inapplicable and therefore have been omitted.
F-1
Report of Independent Registered Public Accounting Firm
The Board of Directors of Delek Logistics GP, LLC and
Unitholders of Delek Logistics Partners, LP
We have audited Delek Logistics Partners, LP’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). Delek Logistics Partners, LP’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Delek Logistics Partners, LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2013 consolidated financial statements of Delek Logistics Partners, LP and our report dated
March 4, 2014
expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Nashville, Tennessee
March 4, 2014
F-2
Report of Independent Registered Public Accounting Firm
The Board of Directors of Delek Logistics GP, LLC and
Unitholders of Delek Logistics Partners, LP
We have audited the accompanying consolidated balance sheets of Delek Logistics Partners, LP as of December 31, 2013 and 2012, and the related consolidated statements of income and comprehensive income, partners' equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Delek Logistics Partners, LP at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Delek Logistics Partners, LP’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated
March 4, 2014
expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Nashville, Tennessee
March 4, 2014
F-3
Delek Logistics Partners, LP
|
December 31,
|
||||||||
|
2013
|
|
2012
(1)
|
||||||
|
|
|
Predecessors
|
||||||
|
(In thousands)
|
||||||||
|
ASSETS
|
|
|
||||||
|
Current assets:
|
|
|
||||||
|
Cash and cash equivalents
|
$
|
924
|
|
|
$
|
23,452
|
|
|
|
Accounts receivable
|
28,976
|
|
|
27,725
|
|
|||
|
Inventory
|
17,512
|
|
|
14,351
|
|
|||
|
Deferred tax assets
|
12
|
|
|
14
|
|
|||
|
Other current assets
|
341
|
|
|
169
|
|
|||
|
Total current assets
|
47,765
|
|
65,711
|
|
||||
|
Property, plant and equipment:
|
|
|
||||||
|
Property, plant and equipment
|
235,588
|
|
216,048
|
|
||||
|
Less: accumulated depreciation
|
(36,306
|
)
|
(24,991
|
)
|
||||
|
Property, plant and equipment, net
|
199,282
|
|
191,057
|
|
||||
|
Goodwill
|
10,454
|
|
10,454
|
|
||||
|
Intangible assets, net
|
12,258
|
|
12,430
|
|
||||
|
Other non-current assets
|
5,045
|
|
3,664
|
|
||||
|
Total assets
|
$
|
274,804
|
|
$
|
283,316
|
|
||
|
LIABILITIES AND EQUITY
|
|
|
||||||
|
Current liabilities:
|
|
|
||||||
|
Accounts payable
|
$
|
26,045
|
|
$
|
21,849
|
|
||
|
Accounts payable to related parties
|
1,513
|
|
10,148
|
|
||||
|
Fuel and other taxes payable
|
5,700
|
|
4,650
|
|
||||
|
Accrued expenses and other current liabilities
|
5,776
|
|
3,650
|
|
||||
|
Total current liabilities
|
39,034
|
|
40,297
|
|
||||
|
Non-current liabilities:
|
|
|
||||||
|
Revolving credit facility
|
164,800
|
|
90,000
|
|
||||
|
Asset retirement obligations
|
2,993
|
|
3,177
|
|
||||
|
Deferred tax liabilities
|
324
|
|
17
|
|
||||
|
Other non-current liabilities
|
5,612
|
|
9,810
|
|
||||
|
Total non-current liabilities
|
173,729
|
|
103,004
|
|
||||
|
Equity:
|
|
|
||||||
|
Predecessor division equity
|
—
|
|
35,590
|
|
||||
|
Common unitholders - public; 9,353,240 units issued and outstanding at December 31, 2013 (9,200,000 at December 31, 2012)
|
183,839
|
|
178,728
|
|
||||
|
Common unitholders - Delek; 2,799,258 units issued and outstanding at December 31, 2013 (2,799,258 at December 31, 2012)
|
(176,680
|
)
|
(127,129
|
)
|
||||
|
Subordinated unitholders - Delek; 11,999,258 units issued and outstanding at December 31, 2013 (11,999,258 at December 31, 2012)
|
59,386
|
|
52,875
|
|
||||
|
General partner - Delek; 492,893 units issued and outstanding at December 31, 2013 (489,766 at December 31, 2012)
|
(4,504
|
)
|
(49
|
)
|
||||
|
Total equity
|
62,041
|
|
140,015
|
|
||||
|
Total liabilities and equity
|
$
|
274,804
|
|
$
|
283,316
|
|
||
(1)
Includes the historical balances of the Tyler Terminal and Tank Assets. See Notes 1 and 3 for further discussion.
See accompanying notes to the consolidated financial statements
F-4
Delek Logistics Partners, LP
|
Year Ended December 31,
|
||||||||||||
|
|
2013
|
2012
|
2011
|
|||||||||
|
Predecesso
rs
(1)
|
Predecessors
(1)
|
|||||||||||
|
|
(In thousands, except unit data and per unit data)
|
|||||||||||
|
Net sales
|
$
|
907,428
|
|
$
|
1,022,586
|
|
$
|
744,079
|
|
|||
|
Operating costs and expenses:
|
|
|||||||||||
|
Cost of goods sold
|
811,364
|
|
959,434
|
|
700,505
|
|
||||||
|
Operating expenses
|
30,302
|
|
30,397
|
|
19,467
|
|
||||||
|
General and administrative expenses
|
6,856
|
|
9,150
|
|
6,483
|
|
||||||
|
Depreciation and amortization
|
12,436
|
|
10,120
|
|
6,061
|
|
||||||
|
Loss (gain) on asset disposals
|
166
|
|
9
|
|
(2
|
)
|
||||||
|
Total operating costs and expenses
|
861,124
|
|
1,009,110
|
|
732,514
|
|
||||||
|
Operating income
|
46,304
|
|
13,476
|
|
11,565
|
|
||||||
|
Interest expense, net
|
4,570
|
|
2,682
|
|
2,011
|
|
||||||
|
Net income before income tax expense (benefit)
|
41,734
|
|
10,794
|
|
9,554
|
|
||||||
|
Income tax expense (benefit)
|
757
|
|
(14,024
|
)
|
5,363
|
|
||||||
|
Net income
|
40,977
|
|
24,818
|
|
4,191
|
|
||||||
|
Less: (Loss) income attributable to Predecessors
|
(6,853
|
)
|
16,408
|
|
4,191
|
|
||||||
|
Net income attributable to partners
|
$
|
47,830
|
|
$
|
8,410
|
|
$
|
—
|
|
|||
|
Comprehensive income attributable to partners
|
$
|
47,830
|
|
$
|
8,410
|
|
$
|
—
|
|
|||
|
Less: General partner's interest in net income
|
957
|
|
168
|
|
||||||||
|
Limited partners' interest in net income
|
$
|
46,873
|
|
$
|
8,242
|
|
||||||
|
Net income per limited partner unit:
|
||||||||||||
|
Common units - (basic)
|
$
|
1.95
|
|
$
|
0.34
|
|
||||||
|
Common units - (diluted)
|
$
|
1.93
|
|
$
|
0.34
|
|
||||||
|
Subordinated units - Delek (basic and diluted)
|
$
|
1.95
|
|
$
|
0.34
|
|
||||||
|
Weighted average limited partner units outstanding:
|
|
|||||||||||
|
Common units - (basic)
|
12,025,249
|
|
11,999,258
|
|
||||||||
|
Common units - (diluted)
|
12,148,774
|
|
11,999,258
|
|
||||||||
|
Subordinated units - Delek (basic and diluted)
|
11,999,258
|
|
11,999,258
|
|
||||||||
|
Cash distributions per unit
|
$
|
1.600
|
|
$
|
0.224
|
|
||||||
(1)
Adjusted
to include the historical results of the Tyler Terminal and Tank Assets. See Notes 1 and 3 for further discussion.
See accompanying notes to the consolidated financial statements
F-5
Delek Logistics Partners, LP
Consolidated Statements of Partners' Equity
|
Partnership
|
||||||||||||||||||||||||
|
Equity of Predecessors
|
Common - Public
|
Common - Delek
|
Subordinated - Delek
|
General Partner - Delek
|
Total
|
|||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||
|
Balance at December 31, 2010
|
$
|
28,643
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
28,643
|
|
||||||
|
Income attributable to Predecessors
|
4,191
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
4,191
|
|
|||||||||||
|
Non-cash contribution of Paline and Contributed Lion Oil Assets opening net assets from Delek
|
80,327
|
|
—
|
|
—
|
|
—
|
|
—
|
|
80,327
|
|
||||||||||||
|
Sponsor contributions of equity to the Predecessor
|
15,897
|
|
—
|
|
—
|
|
—
|
|
—
|
|
15,897
|
|
||||||||||||
|
Other
|
84
|
|
84
|
|
||||||||||||||||||||
|
Balance at December 31, 2011
|
129,142
|
|
—
|
|
—
|
|
—
|
|
—
|
|
129,142
|
|
||||||||||||
|
Contribution of equity to the Sponsor
|
(22,987
|
)
|
—
|
|
—
|
|
—
|
|
|
—
|
|
(22,987
|
)
|
|||||||||||
|
Income attributable to Predecessors
|
16,408
|
|
—
|
|
—
|
|
—
|
|
—
|
|
16,408
|
|
||||||||||||
|
Allocation of net assets contributed to the unitholders
|
(87,090
|
)
|
—
|
|
(11,554
|
)
|
48,753
|
|
49,891
|
|
—
|
|
||||||||||||
|
Equity offering, net of issuance costs
|
—
|
|
175,459
|
|
—
|
|
—
|
|
—
|
|
175,459
|
|
||||||||||||
|
Distributions to unitholders and general partner related to assets acquired in the initial public offering
|
—
|
|
—
|
|
(116,535
|
)
|
—
|
|
(50,000
|
)
|
(166,535
|
)
|
||||||||||||
|
Net income attributable to partners
|
—
|
|
3,160
|
|
960
|
|
4,122
|
|
168
|
|
8,410
|
|
||||||||||||
|
Other
|
117
|
|
109
|
|
—
|
|
—
|
|
(108
|
)
|
118
|
|
||||||||||||
|
Balance at December 31, 2012
|
35,590
|
|
178,728
|
|
(127,129
|
)
|
52,875
|
|
(49
|
)
|
140,015
|
|
||||||||||||
|
Sponsor contributions of equity to the Predecessor
|
9,317
|
|
—
|
|
—
|
|
—
|
|
—
|
|
9,317
|
|
||||||||||||
|
Loss attributable to Predecessor
|
(6,853
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
(6,853
|
)
|
||||||||||||
|
Liabilities not assumed by the Partnership
|
213
|
|
—
|
|
—
|
|
—
|
|
—
|
|
213
|
|
||||||||||||
|
Allocation of net assets acquired by the unitholders
|
(38,267
|
)
|
—
|
|
37,502
|
|
—
|
|
765
|
|
—
|
|
||||||||||||
|
Cash distributions
(1)
|
—
|
|
(13,223
|
)
|
(96,848
|
)
|
(16,907
|
)
|
(2,586
|
)
|
(129,564
|
)
|
||||||||||||
|
Sponsorship contribution of fixed assets
|
—
|
|
—
|
|
510
|
|
—
|
|
10
|
|
520
|
|
||||||||||||
|
Net income attributable to partners
|
—
|
|
18,035
|
|
5,455
|
|
23,383
|
|
957
|
|
47,830
|
|
||||||||||||
|
Unit-based compensation
|
—
|
|
341
|
|
3,822
|
|
—
|
|
(3,699
|
)
|
464
|
|
||||||||||||
|
Other
|
—
|
|
(42
|
)
|
8
|
|
35
|
|
98
|
|
99
|
|
||||||||||||
|
Balance at December 31, 2013
|
$
|
—
|
|
$
|
183,839
|
|
$
|
(176,680
|
)
|
$
|
59,386
|
|
$
|
(4,504
|
)
|
$
|
62,041
|
|
||||||
(1)
Distributions to unitholders and general partner include
$94.8 million
in cash payments for an acquisition from Delek during 2013. As an entity under common control with Delek, we record the assets that we acquire from Delek on our consolidated balance sheet at Delek's historical book value instead of fair value. Additionally, any excess of cash paid over the historical book value of the assets acquired from Delek is recorded within equity. As a result of this accounting treatment, the acquisition resulted in a
$56.5 million
decrease in our equity balance during 2013. Distributions also include
$0.2 million
related to distribution equivalents on vested phantom units.
See accompanying notes to the consolidated financial statements
F-6
|
|
Year Ended December 31,
|
|||||||||||
|
2013
|
2012
|
2011
|
||||||||||
|
Predecessors
(1)
|
Predecessors
(1)
|
|||||||||||
|
Cash flows from operating activities:
|
(In thousands)
|
|||||||||||
|
Net income
|
$
|
40,977
|
|
$
|
24,818
|
|
$
|
4,191
|
|
|||
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
|
||||||||||||
|
Depreciation and amortization
|
12,436
|
|
10,120
|
|
6,061
|
|
||||||
|
Amortization of unfavorable contract liability to revenue
|
(2,623
|
)
|
(668
|
)
|
—
|
|
||||||
|
Amortization of deferred financing costs
|
1,007
|
|
381
|
|
208
|
|
||||||
|
Accretion of asset retirement obligations
|
216
|
|
187
|
|
173
|
|
||||||
|
Loss (gain) on asset disposals
|
166
|
|
9
|
|
(2
|
)
|
||||||
|
Deferred income taxes
|
309
|
|
(18,762
|
)
|
(4,328
|
)
|
||||||
|
Share-based compensation expense
|
—
|
|
92
|
|
64
|
|
||||||
|
Unit-based compensation expense
|
464
|
|
1
|
|
—
|
|
||||||
|
Changes in assets and liabilities, net of acquisitions:
|
||||||||||||
|
Accounts receivable
|
(1,251
|
)
|
(5,148
|
)
|
(2,628
|
)
|
||||||
|
Inventories and other current assets
|
(3,333
|
)
|
4,917
|
|
(10,705
|
)
|
||||||
|
Accounts payable and other current liabilities
|
7,402
|
|
(4,651
|
)
|
9,265
|
|
||||||
|
Accounts payable - related parties
|
(8,635
|
)
|
15,766
|
|
(12,252
|
)
|
||||||
|
Non-current assets and liabilities, net
|
(2,744
|
)
|
(450
|
)
|
(99
|
)
|
||||||
|
Net cash provided by (used in) operating activities
|
44,391
|
|
26,612
|
|
(10,052
|
)
|
||||||
|
Cash flows from investing activities:
|
|
|
||||||||||
|
Business combinations
|
(10,737
|
)
|
(23,272
|
)
|
—
|
|
||||||
|
Purchases of property, plant and equipment
|
(9,398
|
)
|
(26,759
|
)
|
(7,130
|
)
|
||||||
|
Proceeds from sales of property, plant and equipment
|
—
|
|
21
|
|
—
|
|
||||||
|
Net cash used in investing activities
|
(20,135
|
)
|
(50,010
|
)
|
(7,130
|
)
|
||||||
|
Cash flows from financing activities:
|
|
|
||||||||||
|
Proceeds from issuance of common units, net of underwriters' discount
|
—
|
|
179,676
|
|
—
|
|
||||||
|
Proceeds from issuance of additional units to maintain 2% General Partner interest
|
99
|
|
—
|
|
—
|
|
||||||
|
Distributions to general partner
|
(690
|
)
|
(50,000
|
)
|
—
|
|
||||||
|
Distributions to common unitholders - Public
|
(13,223
|
)
|
—
|
|
—
|
|
||||||
|
Distributions to common unitholders - Delek
|
(3,944
|
)
|
(116,535
|
)
|
—
|
|
||||||
|
Distributions to subordinated unitholders
|
(16,907
|
)
|
—
|
|
—
|
|
||||||
|
Distributions to Delek for contribution of Tyler Terminal and Tank Assets
|
(94,800
|
)
|
—
|
|
—
|
|
||||||
|
Proceeds from revolving credit facility
|
206,300
|
|
351,900
|
|
197,300
|
|
||||||
|
Payments of revolving credit facility
|
(131,500
|
)
|
(292,200
|
)
|
(196,000
|
)
|
||||||
|
Tax benefit from exercise of equity-based compensation
|
—
|
|
25
|
|
20
|
|
||||||
|
Offering costs
|
—
|
|
(4,217
|
)
|
—
|
|
||||||
|
Deferred financing costs paid
|
(2,273
|
)
|
(3,821
|
)
|
—
|
|
||||||
|
Predecessor division equity contribution (distribution)
|
9,317
|
|
(22,511
|
)
|
15,897
|
|
||||||
|
Reimbursement of capital expenditures by Sponsor
|
837
|
|
4,498
|
|
—
|
|
||||||
|
Net cash (used in) provided by financing activities
|
(46,784
|
)
|
46,815
|
|
17,217
|
|
||||||
|
Net (decrease) increase in cash and cash equivalents
|
(22,528
|
)
|
23,417
|
|
35
|
|
||||||
|
Cash and cash equivalents at the beginning of the period
|
23,452
|
|
35
|
|
—
|
|
||||||
|
Cash and cash equivalents at the end of the period
|
$
|
924
|
|
$
|
23,452
|
|
$
|
35
|
|
|||
|
|
Year Ended December 31,
|
|||||||||||
|
2013
|
2012
|
2011
|
||||||||||
|
Predecessors
(1)
|
Predecessors
(1)
|
|||||||||||
|
Supplemental disclosures of cash flow information:
|
|
|
||||||||||
|
Cash paid during the period for:
|
|
|
||||||||||
|
Interest
|
$
|
3,242
|
|
$
|
2,006
|
|
$
|
1,807
|
|
|||
|
Taxes
|
$
|
30
|
|
$
|
1,316
|
|
$
|
56
|
|
|||
|
Non-cash financing activities:
|
|
|
|
|
||||||||
|
Working capital retained by Sponsor
|
$
|
213
|
|
$
|
63,847
|
|
$
|
—
|
|
|||
|
Sponsor contribution of fixed assets
|
$
|
520
|
|
$
|
476
|
|
$
|
—
|
|
|||
(1)
Adjusted
to include the historical cash flows of the Tyler Terminal and Tank Assets. See Notes 1 and 3 for further discussion.
See accompanying notes to the consolidated financial statements
F-7
Delek Logistics Partners, LP
Notes to Consolidated Financial Statements
1
. General
Organization and Basis of Presentation
As used in this report, the terms "Delek Logistics Partners, LP," the "Partnership," "we," "us," or "our" may refer to Delek Logistics Partners, LP, one or more of its consolidated subsidiaries or all of them taken as a whole. References in this report to "Delek" refer collectively to Delek US Holdings, Inc. and any of its subsidiaries, other than Delek Logistics Partners, LP, its subsidiaries and its general partner. The information presented in this Annual Report on Form 10-K contains the combined financial results of Delek Logistics Partners, LP Predecessor (the "DKL Predecessor"), our predecessor for accounting purposes, for periods presented through November 6, 2012. The consolidated financial results for the year ended
December 31, 2012
also include the results of operations for Delek Logistics Partners, LP for the period beginning November 7, 2012, the date the Partnership commenced operations. The DKL Predecessor includes the financial results of the initial assets acquired from Delek during the initial public offering through November 7, 2012. The balance sheet as of
December 31, 2013
presents solely the consolidated financial position of the Partnership.
The Partnership is a Delaware limited partnership formed in April 2012 by Delek and its subsidiary Delek Logistics GP, LLC, our general partner. On November 7, 2012, we completed our initial public offering (the "Offering") of
9,200,000
common units, representing limited partner interests.
Upon completion of the Offering, the Partnership consisted of the assets, liabilities and results of operations of certain crude oil and refined product pipelines and transportation, wholesale marketing and terminalling assets previously operated or held by Delek and certain of its present subsidiaries including Delek Marketing & Supply, LLC ("Delek Marketing") and Lion Oil Company ("Lion Oil") and former subsidiaries including Paline Pipeline Company, LLC ("Paline"), which is now a subsidiary of the Partnership. Prior to the completion of the Offering, the assets, liabilities, and results of operations of the aforementioned assets related to the DKL Predecessor.
On July 26, 2013, we acquired from Delek (i) the refined products terminal (the “Tyler Terminal”) located at Delek's Tyler, Texas Refinery (the "Tyler Refinery") and (ii) ninety-six storage tanks and certain ancillary assets (the "Tyler Tank Assets" and together, with the Tyler Terminal, the “Tyler Terminal and Tank Assets”) adjacent to the Tyler Refinery (such transaction, the “Tyler Acquisition”). The Tyler Acquisition was a transfer between entities under common control. Accordingly, the accompanying financial statements and related notes of the DKL Predecessor and the Partnership have been retrospectively adjusted to include the historical results of the Tyler Terminal and Tank Assets for all periods presented through July 26, 2013 (the "Tyler Predecessor"). We refer to the historical results of the DKL Predecessor and the Tyler Predecessor collectively as our "Predecessors." See
Note 3
for further information regarding the Tyler Acquisition.
Description of Business
The Partnership owns and operates crude oil and refined products logistics and marketing assets. A substantial majority of our existing assets are integral to and dependent on the success of Delek’s refining and marketing operations. We gather, transport and store crude oil and market, distribute, transport and store refined products in select regions of the southeastern United States and west Texas for Delek and third parties, primarily in support of Delek’s refineries in Tyler, Texas (the "Tyler Refinery") and El Dorado, Arkansas (the "El Dorado Refinery").
The Partnership generates revenue by charging fees for gathering, transporting and storing crude oil and for marketing, distributing, transporting and storing refined products. A substantial majority of our contribution margin, which we define as net sales less cost of goods sold and operating expenses, is derived from commercial agreements with Delek with initial terms ranging from five to ten years.
2
. Accounting Policies
Basis of Presentation
Our consolidated financial statements include the accounts of the Partnership and its subsidiaries as well as our Predecessors. All intercompany accounts and transactions have been eliminated. The financial statements of our Predecessors have been prepared from the separate records maintained by Delek and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessors had been operated as an unaffiliated entity. Our Predecessors did not record all revenues for intercompany gathering, pipeline transportation, terminalling and storage services. Transfers between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are
retrospectively adjusted to furnish comparative information. As an entity under common control with Delek, we record the assets that Delek has contributed to us on our balance sheet at Delek's historical basis instead of fair value.
We have evaluated subsequent events through the filing of this Annual Report on Form 10-K. Any material subsequent events that occurred during this time have been properly recognized or disclosed in our financial statements. The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Segment Reporting
We are an energy business focused on crude oil and refined product pipeline, storage, wholesale marketing and terminalling activities. Management reviews operating results in two reportable segments: (i) pipelines and transportation and (ii) wholesale marketing and terminalling. The pipelines and transportation segment provides crude oil gathering, transportation and storage services to Delek's refining operations and independent third parties. The wholesale marketing and terminalling segment provides marketing and terminalling services to Delek's refining operations and independent third parties. Decisions concerning the allocation of resources and assessment of operating performance are made based on this segmentation. Management measures the operating performance of each of its reportable segments based on the segment contribution margin. Segment contribution margin is defined as net sales less cost of sales and operating expenses, excluding depreciation and amortization. Segment reporting is more fully discussed in
Note 13
.
Cash and Cash Equivalents
We maintain cash and cash equivalents in accounts with large, national financial institutions. All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents. As of
December 31, 2013
and
2012
, any cash equivalents consisted primarily of overnight investments in U.S. Government obligations, bank repurchase obligations collateralized by U.S. Government obligations and bank money market accounts.
Accounts Receivable
Accounts receivable primarily consists of trade receivables generated in the ordinary course of business. We perform on-going credit evaluations of our customers and generally do not require collateral on accounts receivable. All accounts receivable amounts are considered to be fully collectible. Accordingly, no allowance has been established as of
December 31, 2013
and
2012
.
Two customers accounted for approximately
27.2%
and
18.9%
of the consolidated accounts receivable balance as of
December 31, 2013
and
2012
, respectively.
Inventory
Inventory consists of refined products, which are stated at the lower of cost or market on a FIFO basis.
Two vendors in the wholesale marketing and terminalling segment accounted for a total of
96.1%
,
76.1%
and
96.8%
of our consolidated inventory purchases during the years ended
December 31, 2013
,
2012
and
2011
, respectively.
Property, Plant and Equipment
Assets acquired in conjunction with acquisitions are recorded at estimated fair market value in accordance with the purchase method of accounting as prescribed in Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards Codification ("ASC") 805,
Business Combinations
("ASC 805"). Other acquisitions of property and equipment are carried at cost.
Betterments, renewals and extraordinary repairs that extend the life of an asset are capitalized. Maintenance and repairs are charged to expense as incurred.
F-9
Depreciation is computed using the straight-line method over management’s estimated useful lives of the related assets, except for automotive equipment, which is depreciated using a declining-balance method. The estimated useful lives are as follows:
|
Years
|
|
|
Building and pipeline improvements
|
15-40
|
|
Pipelines and terminals
|
15-40
|
|
Asset retirement obligation assets
|
15-50
|
|
Other equipment
|
3-15
|
Intangible Assets
Intangible assets consist of long-term supply contracts and indefinite-lived rights of way. We amortize the definite-lived long-term supply contracts on a straight-line basis over the estimated useful life of
11.5
years. The amortization expense is included in depreciation and amortization in the accompanying consolidated statements.
Property, Plant and Equipment and Intangibles Impairment
Property, plant and equipment and definite life intangibles are evaluated for impairment whenever indicators of impairment exist. In accordance with ASC 360, Property, Plant and Equipment and ASC 350, Intangibles - Goodwill and Other, we evaluate the realizability of these long-lived assets as events occur that might indicate potential impairment. In doing so, we assess whether the carrying amount of the asset is unrecoverable by estimating the sum of the future cash flows expected to result from the asset, undiscounted and without interest charges. If the carrying amount is more than the recoverable amount, an impairment charge must be recognized based on the fair value of the asset.
Goodwill and Potential Impairment
Goodwill in an acquisition represents the excess of the aggregate purchase price over the fair value of the identifiable net assets. Our goodwill is recorded at original fair value and is not amortized. Goodwill is subject to annual assessment to determine if an impairment of value has occurred and we perform this review annually in the fourth quarter. We could also be required to evaluate our goodwill if, prior to our annual assessment, we experience disruptions in our business, have unexpected significant declines in operating results, or sustain a permanent market capitalization decline. If an asset’s carrying amount exceeds its fair value, the impairment assessment leads to the testing of the implied fair value of the asset’s goodwill to its carrying amount. If the implied fair value is less than the carrying amount, a goodwill impairment charge is recorded. Our annual assessment of goodwill did not result in an impairment charge during the years ended
December 31, 2013
,
2012
, or
2011
.
Derivatives
We record all derivative financial instruments, including forward fuel contracts, at estimated fair value in accordance with the provisions of ASC 815, Derivatives and Hedging ("ASC 815"). Changes in the fair value of the derivative instruments are recognized in operations, unless we elect to apply the hedging treatment permitted under the provisions of ASC 815 allowing such changes to be classified as other comprehensive income. We validate the fair value of all derivative financial instruments on a monthly basis, utilizing valuations from third party financial and brokerage institutions. During the years ended
December 31, 2013
,
2012
, and
2011
, we did not elect to apply hedging treatment to our derivative positions and, therefore, all changes in fair value are reflected in the statements of operations.
Our policy under the guidance of ASC 815-10-45, Derivatives and Hedging—Other Presentation Matters ("ASC 815-10-45"), is to net the fair value amounts recognized for multiple derivative instruments executed with the same counterparty and offset these values against the cash collateral arising from these derivative positions.
Fair Value of Financial Instruments
The fair values of financial instruments are estimated based upon current market conditions and quoted market prices for the same or similar instruments. Management estimates that the carrying value approximates fair value for all of our assets and liabilities that fall under the scope of ASC 825, Financial Instruments ("ASC 825").
We apply the provisions of ASC 820, Fair Value Measurements and Disclosure ("ASC 820"), in our presentation and disclosures regarding fair value, which pertain to certain financial assets and liabilities measured at fair value in the statement of position on a recurring basis. ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about such measurements that are permitted or required under other accounting pronouncements. See
Note 14
for further discussion.
F-10
We apply the provisions of ASC 825 as it pertains to the fair value option. This standard permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. As of
December 31, 2013
or
2012
, we did not make the fair value election for any financial instruments not already carried at fair value in accordance with other standards.
Self-Insurance Reserves
We have no employees. Rather, we are managed by the directors and officers of our general partner. However, Delek employees providing services to the Partnership are covered under Delek’s insurance programs. Delek is primarily self-insured for workers' compensation and general liability costs, with varying limits of per claim and aggregate stop loss insurance coverage that management considers adequate. Delek has umbrella liability insurance in an amount determined reasonable by Delek's management.
Environmental Expenditures
We have historically accrued environmental and clean-up related costs of a non-capital nature when it is both probable that a liability has been incurred and the amount can be reasonably estimated. Environmental liabilities represent the current estimated costs to investigate and remediate contamination at our properties. This estimate is based on internal and third-party assessments of the extent of the contamination, the selected remediation technology and review of applicable environmental regulations, typically considering estimated activities and costs for the next 15 years, unless a specific longer range estimate is practicable. Accruals for estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study and include, but are not limited to, costs to perform remedial actions and costs of machinery and equipment that are dedicated to the remedial actions and that does not have an alternative use. Such accruals are adjusted as further information develops or circumstances change. We discount environmental liabilities to their present value if payments are fixed and determinable. Expenditures for equipment necessary for environmental issues relating to ongoing operations are capitalized. Estimated recoveries of costs from other parties are recorded on an undiscounted basis as assets when their realization is deemed probable.
Asset Retirement Obligations
We recognize liabilities which represent the fair value of a legal obligation to perform asset retirement activities, including those that are conditional on a future event, when the amount can be reasonably estimated. These obligations are related to the required cleanout of our pipelines and terminal tanks, and removal of certain above-grade portions of our pipelines situated on right-of-way property.
The reconciliation of the beginning and ending carrying amounts of asset retirement obligations as of
December 31, 2013
and
2012
is as follows (in thousands):
|
December 31,
|
||||||||
|
2013
|
2012
|
|||||||
|
Beginning balance
|
$
|
3,177
|
|
$
|
2,990
|
|
||
|
Liabilities settled
|
(400
|
)
|
—
|
|
||||
|
Accretion expense
|
216
|
|
187
|
|
||||
|
Ending balance
|
$
|
2,993
|
|
$
|
3,177
|
|
||
In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation.
Other Non-current Liabilities
We recognized in 2011 an estimated
$6.0 million
liability associated with a customer contract in our December 2011 acquisition of Paline. We amortized approximately
$2.6 million
to revenue during
2013
.
No
amounts were remaining in other non-current liabilities as of
December 31, 2013
. The amount to amortize in
2014
is included in other current liabilities. We assumed in 2011 an estimated
$2.9 million
of non-current tank and pipeline inspection liabilities in the Lion Oil Acquisition, of which $
0.8 million
was outstanding as of
December 31, 2013
. During the fourth quarter of 2012, we recognized a liability of $
4.5 million
related to Delek's reimbursement of maintenance capital associated with three existing capital projects per the Omnibus Agreement (as defined below in
Note 18
—Related Party Transactions). This liability will be amortized to revenue over the estimated lives of the assets once placed in service. The outstanding liability as of
December 31, 2013
was
$4.3 million
.
F-11
Revenue Recognition
Revenues for products sold are recorded at the point of sale upon delivery of product, which is the point at which title to the product is transferred, and when payment has either been received or collection is reasonably assured. Service revenues are recognized as crude oil and refined products are shipped through, delivered by or stored in our pipelines, terminals and storage facility assets, as applicable. We do not recognize product sales revenues for these services, as title on the product never passes to us. All revenues are based on regulated tariff rates or contractual rates.
Cost of Goods Sold and Operating Expenses
Cost of goods sold includes all costs of refined products, additives and related transportation. We do not recognize product cost of sales related to our shipping, delivering and storage services, as title to the product never passes to us. Operating expenses include the costs associated with the operation of owned terminals, terminalling expense at third-party locations and pipeline maintenance costs.
Sales, Use and Excise Taxes
Our policy is to exclude sales, use and excise taxes from revenue when we are an agent of the taxing authority, in accordance with ASC 605-45,
Revenue Recognition—Principal Agent Considerations
.
Deferred Financing Costs
Deferred financing costs are included in other non-current assets in the accompanying balance sheets and represent expenses related to issuing and amending our revolving credit facility. These amounts are amortized ratably over the remaining term of our revolving credit facility and are included in interest expense in the accompanying consolidated financial statements.
Operating Leases
We lease certain equipment and have surface leases under various operating lease arrangements, most of which provide the option, after the initial lease term, to renew the leases. None of these lease arrangements include fixed rental rate increases.
Lease expense for all operating leases, including the Tyler Predecessor, totaled $
0.5 million
, $
0.5 million
, and $
0.3 million
for the years ended
December 31, 2013
,
2012
, and
2011
, respectively.
Income Taxes
We are not a taxable entity for federal income tax purposes or the income taxes of those states that follow the federal income tax treatment of partnerships. Instead, for purposes of these income taxes, each partner of the Partnership is required to take into account his, her or its share of items of income, gain, loss and deduction in computing his, her or its federal and state income tax liabilities, regardless of whether cash distributions are made to such partner by the Partnership. The taxable income reportable to each partner takes into account differences between the tax basis and fair market value of our assets, the acquisition price of such partner's units and the taxable income allocation requirements under our partnership agreement.
We are subject to income taxes in certain states that do not follow the federal tax treatment of Partnerships. These income taxes are accounted for under the provisions of ASC 740, Income Taxes (ASC 740). This statement generally requires DKL to record deferred income taxes for the differences between the book and tax bases of its assets and liabilities, which are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. Deferred income tax expense or benefit represents the net change during the year in our deferred income tax assets and liabilities, exclusive of the amounts held in other comprehensive income.
U.S. GAAP requires management to evaluate uncertain tax positions taken by the Partnership. The financial statement effects of a tax position are recognized when the position is more likely than not, based on the technical merits, to be sustained upon examination by the Internal Revenue Service. Management has analyzed the tax positions taken by the Partnership, and has concluded that there are no uncertain positions taken or expected to be taken. The Partnership is subject to routine audits by taxing jurisdictions; however, there are currently no audits for any tax periods in progress.
Prior to the Offering, the Predecessor was a corporation included in its parent's consolidated tax return. As such, the Predecessor was subject to both federal and state income taxes and recorded deferred income taxes for the differences between the book and tax bases of its assets and liabilities, which are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse.
The Partnership had total tax expense of
$0.8 million
in
2013
. Subsequent to the Offering, the Partnership had total tax expense of
$0.1 million
in
2012
. The majority of the change in deferred tax assets and liabilities relates to the Predecessor's conversion to a partnership and no longer being subject to federal income tax. The conversion from a taxable corporation to a passthrough resulted in a one-time tax benefit of
$18.5 million
in 2012.
F-12
Equity Based Compensation
Our general partner provides equity-based compensation to officers, directors and employees of our general partner or its affiliates, and certain consultants, affiliates of our general partner or other individuals who perform services for us, which includes unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. Phantom units are measured based on the fair market value of the underlying stock on the date of grant. The fair value of our phantom units is determined based on the closing price of our common units on the grant date. The estimated fair value of our phantom units is amortized over the vesting period using the straight line method. Awards vest over a
five
-year service period. The phantom unit awards are settled in units.
Comprehensive Income
Comprehensive income for the years ended
December 31, 2013
,
2012
, and
2011
was equivalent to net income.
New Accounting Pronouncements
In July 2012, the FASB issued guidance regarding testing indefinite-lived intangible assets for impairment that gives companies the option to perform a qualitative assessment before calculating the fair value of the indefinite-lived intangible asset. Under the guidance, if this option is selected, a company is not required to calculate the fair value of the indefinite-lived intangible unless the entity determines it is more likely than not that its fair value is less than its carrying amount. In October 2012, the FASB issued guidance regarding the application of the qualitative assessment permitted under the Accounting Standards Update 2012-02, issued in July. The guidance requires companies to focus on the significant inputs used to determine the fair value of indefinite-lived intangible assets when companies opt to perform the qualitative assessment. Companies must then evaluate the impact of certain events and circumstances that could have affected those inputs and weigh the identified factors prior to concluding whether the asset is impaired. As significant judgment is applied to conclude that an indefinite-lived intangible asset is not impaired based on a qualitative assessment, the analyses performed by the Company should be supported by clear documentation of the factors considered, including any necessary quantitative calculations. The guidance is effective for interim and annual reporting periods beginning January 1, 2013, but early adoption is permitted. The adoption of this guidance did not affect our business, financial position or results of operations.
In December 2011, the FASB issued guidance requiring the disclosure of information about offsetting and related arrangements to enable users of financial statements to understand the effect of these arrangements on financial position. The guidance requires the disclosure of both gross information and net information about both instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master netting arrangement. In January 2013, the FASB issued an update limiting the scope of the offsetting disclosure requirements established by the original guidance, to certain derivatives (including bifurcated embedded derivatives), repurchase agreements and reverse repurchase agreements, and securities lending and securities borrowing transactions that are eligible for offset on the balance sheet or are subject to an agreement similar to a master netting arrangement, irrespective of whether they are offset on the balance sheet. This update amends the guidance that required companies to apply the requirements to all recognized financial instruments. The original and updated guidance is effective for interim and annual reporting periods beginning January 1, 2013 and retrospectively for all periods presented on the balance sheet. The adoption of this guidance did not affect our business, financial position or results of operations, but resulted in additional disclosures (see
Note 14
).
3
. Acquisitions
North Little Rock Acquisition
On
October 24, 2013
, we purchased a refined product terminal in Little Rock, Arkansas from Enterprise Refined Products Company, LLC (the "North Little Rock Terminal"). We acquired the North Little Rock Terminal to expand our customer base and diversify our product mix. The aggregate purchase price was approximately
$5.0 million
. The allocation of the purchase price was based primarily upon a preliminary valuation. The preliminary valuation is subject to change during the purchase price allocation period.
The preliminary allocation of the aggregate purchase price of the North Little Rock Terminal as of
December 31, 2013
is summarized as follows (in thousands):
|
Property, plant and equipment
|
$
|
4,987
|
|
|
Intangible assets
|
13
|
|
|
|
Total
|
$
|
5,000
|
|
F-13
Pro Forma Financial Information - North Little Rock Acquisition
We began consolidating the results of operations of the North Little Rock Terminal on
October 24, 2013
. The North Little Rock Terminal contributed
$0.2 million
and
$0.1 million
to net sales and net income, respectively, for the
year ended
December 31, 2013
. Below are the unaudited pro forma consolidated results of operations for the years ended
December 31, 2013
and
2012
, as if these acquisitions had occurred on January 1,
2012
(in thousands):
|
Year Ended December 31,
|
||||||||
|
2013
|
2012
|
|||||||
|
Net sales
|
$
|
908,867
|
|
$
|
1,024,025
|
|
||
|
Net income
|
$
|
42,268
|
|
$
|
26,109
|
|
||
Tyler Acquisition
On
July 26, 2013
, the Partnership completed the Tyler Acquisition and acquired the Tyler Terminal and Tank Assets. The purchase price paid for the assets acquired was
$94.8 million
in cash. The assets acquired consisted of the following:
|
•
|
The Tyler Terminal.
The refined products terminal located at the Tyler Refinery, which consists of a truck loading rack with nine loading bays supplied by pipelines from storage tanks, also owned by the Partnership, located adjacent to the Tyler Refinery, along with certain ancillary assets. Total throughput capacity for the Tyler Terminal is approximately
72,000
barrels per day ("bpd").
|
|
•
|
The Tyler Tank Assets.
Ninety-six storage tanks and certain ancillary assets (such as tank pumps and piping) located adjacent to the Tyler Refinery with an aggregate shell capacity of approximately
2.0 million
barrels (the "Tyler Storage Tanks").
|
Delek retained any current assets, current liabilities and environmental liabilities related to the Tyler Terminal and Tank Assets as of the date of the Tyler Acquisition. The only historical balance sheet items that transferred to the Partnership in the Acquisition were property, plant and equipment assets and asset retirement obligations which were recorded by us at historical cost.
In connection with the Tyler Acquisition, the Partnership and Delek (i) entered into an asset purchase agreement, (ii) entered into the First Omnibus Amendment (as defined below in
Note 18
—Related Party Transactions, (iii) entered into a throughput and tankage agreement with respect to the Tyler Terminal and Tank Assets, (iv) entered into a lease and access agreement and (v) entered into a site services agreement. See
Note 18
for additional information regarding these agreements.
Tyler Terminal and Tank Assets Financial Results
The acquisition of the Tyler Terminal and Tank Assets was considered a transfer of a business between entities under common control. Accordingly, the Tyler Acquisition was recorded at amounts based on the historical carrying value of the Tyler Terminal and Tank Assets as of
July 26, 2013
, which was
$38.3 million
. Our historical financial statements have been retrospectively adjusted to reflect the results of operations, financial position, cash flows and equity attributable to the Tyler Terminal and Tank Assets as if we owned the assets for all periods presented. The results of the Tyler Terminal and the Tyler Tank Assets are included in the wholesale marketing and terminalling segment and the pipelines and transportation segment, respectively.
The results of the Tyler Terminal and Tank Assets operations prior to the completion of the Tyler Acquisition on
July 26, 2013
have been included in the Tyler Predecessor results in the tables below. The results of the Tyler Terminal and Tank Assets subsequent to
July 26, 2013
have been included in the Partnership's results. Accordingly, for the
year ended
December 31, 2013
, total operating revenues of
$7.5 million
and net income attributable to the Partnership of
$3.9 million
associated with the Tyler Terminal and Tank Assets are included in the combined consolidated statements of operations of the Partnership. Costs associated with the Tyler Acquisition in the amount of
$0.3 million
are included in general and administrative expenses for the
year ended
December 31, 2013
.
The tables on the following page present our results of operations, the effect of including the results of the Tyler Terminal and Tank Assets and the adjusted total amounts included in our combined consolidated financial statements.
F-14
Combined Consolidated Balance Sheet as of December 31, 2012
|
Delek Logistics
|
Tyler Terminal and Tank Assets
|
Delek Logistics Partners, LP
|
||||||||||
|
Partners, LP
|
(Tyler Predecessor)
|
December 31, 2012
|
||||||||||
|
(In thousands)
|
||||||||||||
|
ASSETS
|
||||||||||||
|
Current Assets:
|
||||||||||||
|
Cash and cash equivalents
|
$
|
23,452
|
|
$
|
—
|
|
$
|
23,452
|
|
|||
|
Accounts receivable
|
27,725
|
|
—
|
|
27,725
|
|
||||||
|
Inventory
|
14,351
|
|
—
|
|
14,351
|
|
||||||
|
Deferred tax assets
|
14
|
|
—
|
|
14
|
|
||||||
|
Other current assets
|
169
|
|
—
|
|
169
|
|
||||||
|
Total current assets
|
65,711
|
|
—
|
|
65,711
|
|
||||||
|
Property, plant and equipment:
|
||||||||||||
|
Property, plant and equipment
|
172,300
|
|
43,748
|
|
216,048
|
|
||||||
|
Less: accumulated depreciation
|
(18,790
|
)
|
(6,201
|
)
|
(24,991
|
)
|
||||||
|
Property, plant and equipment, net
|
153,510
|
|
37,547
|
|
191,057
|
|
||||||
|
Goodwill
|
10,454
|
|
—
|
|
10,454
|
|
||||||
|
Intangible assets, net
|
12,430
|
|
—
|
|
12,430
|
|
||||||
|
Other non-current assets
|
3,664
|
|
—
|
|
3,664
|
|
||||||
|
Total assets
|
$
|
245,769
|
|
$
|
37,547
|
|
$
|
283,316
|
|
|||
|
LIABILITIES AND EQUITY
|
||||||||||||
|
Current liabilities:
|
||||||||||||
|
Accounts payable
|
$
|
21,849
|
|
$
|
—
|
|
$
|
21,849
|
|
|||
|
Accounts payable to related parties
|
10,148
|
|
—
|
|
10,148
|
|
||||||
|
Fuel and other taxes payable
|
4,650
|
|
—
|
|
4,650
|
|
||||||
|
Accrued expenses and other current liabilities
|
3,615
|
|
35
|
|
3,650
|
|
||||||
|
Total current liabilities
|
40,262
|
|
35
|
|
40,297
|
|
||||||
|
Non-current liabilities:
|
||||||||||||
|
Revolving credit facility
|
90,000
|
|
—
|
|
90,000
|
|
||||||
|
Asset retirement obligations
|
1,440
|
|
1,737
|
|
3,177
|
|
||||||
|
Deferred tax liability
|
17
|
|
—
|
|
17
|
|
||||||
|
Other non-current liabilities
|
9,625
|
|
185
|
|
9,810
|
|
||||||
|
Total non-current liabilities
|
101,082
|
|
1,922
|
|
103,004
|
|
||||||
|
Equity:
|
||||||||||||
|
Predecessors division equity
|
—
|
|
35,590
|
|
35,590
|
|
||||||
|
Common unitholders - public (9,200,000 units issued and outstanding)
|
178,728
|
|
—
|
|
178,728
|
|
||||||
|
Common unitholders - Delek (2,799,258 units issued and outstanding)
|
(127,129
|
)
|
—
|
|
(127,129
|
)
|
||||||
|
Subordinated unitholders - Delek (11,999,258 units issued and outstanding)
|
52,875
|
|
—
|
|
52,875
|
|
||||||
|
General Partner unitholders - Delek (489,766 units issued and outstanding)
|
(49
|
)
|
—
|
|
(49
|
)
|
||||||
|
Total equity
|
104,425
|
|
35,590
|
|
140,015
|
|
||||||
|
Total liabilities and equity
|
$
|
245,769
|
|
$
|
37,547
|
|
$
|
283,316
|
|
|||
F-15
Combined Consolidated Statements of Income
|
Delek Logistics
|
Tyler Terminal and Tank Assets
|
Year Ended
|
||||||||||
|
Partners, LP
|
(Tyler Predecessor)
|
December 31, 2013
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Net Sales
|
$
|
907,428
|
|
$
|
—
|
|
$
|
907,428
|
|
|||
|
Operating costs and expenses:
|
||||||||||||
|
Cost of goods sold
|
811,364
|
|
—
|
|
811,364
|
|
||||||
|
Operating expenses
|
25,801
|
|
4,501
|
|
30,302
|
|
||||||
|
General and administrative expenses
|
6,254
|
|
602
|
|
6,856
|
|
||||||
|
Depreciation and amortization
|
10,686
|
|
1,750
|
|
12,436
|
|
||||||
|
Loss on asset disposals
|
166
|
|
—
|
|
166
|
|
||||||
|
Total operating costs and expenses
|
854,271
|
|
6,853
|
|
861,124
|
|
||||||
|
Operating income (loss)
|
53,157
|
|
(6,853
|
)
|
46,304
|
|
||||||
|
Interest expense, net
|
4,570
|
|
—
|
|
4,570
|
|
||||||
|
Net income (loss) before income tax expense
|
48,587
|
|
(6,853
|
)
|
41,734
|
|
||||||
|
Income tax expense
|
757
|
|
—
|
|
757
|
|
||||||
|
Net income (loss)
|
47,830
|
|
(6,853
|
)
|
40,977
|
|
||||||
|
Less: (Loss) attributable to Predecessors
|
—
|
|
(6,853
|
)
|
(6,853
|
)
|
||||||
|
Net income attributable to partners
|
$
|
47,830
|
|
$
|
—
|
|
$
|
47,830
|
|
|||
|
Tyler Terminal and
|
Year Ended
|
|||||||||||
|
Delek Logistics
|
Tank Assets
|
December 31, 2012
|
||||||||||
|
Partners, LP
|
(Tyler Predecessor)
|
(Predecessors)
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Net Sales
|
$
|
1,022,586
|
|
$
|
—
|
|
$
|
1,022,586
|
|
|||
|
Operating costs and expenses:
|
||||||||||||
|
Cost of goods sold
|
959,434
|
|
—
|
|
959,434
|
|
||||||
|
Operating expenses
|
23,362
|
|
7,035
|
|
30,397
|
|
||||||
|
General and administrative expenses
|
8,389
|
|
761
|
|
9,150
|
|
||||||
|
Depreciation and amortization
|
8,675
|
|
1,445
|
|
10,120
|
|
||||||
|
Loss on asset disposals
|
9
|
|
—
|
|
9
|
|
||||||
|
Total operating costs and expenses
|
999,869
|
|
9,241
|
|
1,009,110
|
|
||||||
|
Operating income (loss)
|
22,717
|
|
(9,241
|
)
|
13,476
|
|
||||||
|
Interest expense, net
|
2,682
|
|
—
|
|
2,682
|
|
||||||
|
Net income (loss) before income tax expense
|
20,035
|
|
(9,241
|
)
|
10,794
|
|
||||||
|
Income tax benefit
|
(14,024
|
)
|
—
|
|
(14,024
|
)
|
||||||
|
Net income (loss)
|
34,059
|
|
(9,241
|
)
|
24,818
|
|
||||||
|
Less: Income (loss) attributable to Predecessors
|
25,649
|
|
(9,241
|
)
|
16,408
|
|
||||||
|
Net income attributable to partners
|
$
|
8,410
|
|
$
|
—
|
|
$
|
8,410
|
|
|||
F-16
|
Delek Logistics
|
Tyler Terminal and
|
Year Ended
|
||||||||||
|
Partners, LP
|
Tank Assets
|
December 31, 2011
|
||||||||||
|
(DKL Predecessor)
|
(Tyler Predecessor)
|
(Predecessors)
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Net Sales
|
$
|
744,079
|
|
$
|
—
|
|
$
|
744,079
|
|
|||
|
Operating costs and expenses:
|
||||||||||||
|
Cost of goods sold
|
700,505
|
|
—
|
|
700,505
|
|
||||||
|
Operating expenses
|
12,940
|
|
6,527
|
|
19,467
|
|
||||||
|
General and administrative expenses
|
5,795
|
|
688
|
|
6,483
|
|
||||||
|
Depreciation and amortization
|
4,820
|
|
1,241
|
|
6,061
|
|
||||||
|
Gain on disposal of assets
|
(2
|
)
|
—
|
|
(2
|
)
|
||||||
|
Total operating costs and expenses
|
724,058
|
|
8,456
|
|
732,514
|
|
||||||
|
Operating income (loss)
|
20,021
|
|
(8,456
|
)
|
11,565
|
|
||||||
|
Interest expense, net
|
2,011
|
|
—
|
|
2,011
|
|
||||||
|
Income (loss) before income tax expense
|
18,010
|
|
(8,456
|
)
|
9,554
|
|
||||||
|
Income tax expense
|
5,363
|
|
—
|
|
5,363
|
|
||||||
|
Net income (loss)
|
12,647
|
|
(8,456
|
)
|
4,191
|
|
||||||
|
Less: (Loss) income attributable to Predecessors
|
12,647
|
|
(8,456
|
)
|
4,191
|
|
||||||
|
Net income attributable to partners
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|||
Hopewell Acquisition
On
July 19, 2013
, the Partnership purchased from Enterprise TE Products Pipeline Company LLC a 13.5 mile pipeline (the "Hopewell Pipeline") that originates at the Tyler Refinery and terminates at the Hopewell Station, where it effectively connects to the Big Sandy Pipeline. The Hopewell Pipeline and the Big Sandy Pipeline form essentially one pipeline link between the Tyler Refinery and the Big Sandy Terminal (the "Tyler-Big Sandy Pipeline").
The aggregate purchase price was approximately
$5.7 million
. The allocation of the purchase price was based primarily upon a preliminary valuation. During 2013, we adjusted certain of the acquisition-date fair values previously disclosed, based primarily on an analysis of intangible assets. The preliminary valuation is subject to change during the purchase price allocation period.
The preliminary allocation of the aggregate purchase price of the Hopewell Pipeline as of
December 31, 2013
is summarized as follows (in thousands):
|
Property, plant and equipment
|
$
|
4,836
|
|
|
Intangible assets
|
864
|
|
|
|
Total
|
$
|
5,700
|
|
Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline).
In connection with the acquisition of the Hopewell Pipeline, on July 25, 2013, the Partnership and Delek entered into the Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline), which amended and restated the Terminalling Services Agreement dated November 7, 2012 for the Big Sandy Terminal to include, among other things, a minimum throughput commitment and a per barrel throughput fee that Delek will pay us for throughput along the Tyler-Big Sandy Pipeline. See
Note 18
for additional information on this agreement.
F-17
Pro Forma Financial Information - Hopewell Acquisition
We began consolidating the results of operations of the Hopewell Pipeline on July 19, 2013. Although the Hopewell Pipeline has not been operational since prior to January 1, 2012 due to required maintenance to return it to service, Delek paid to us pipeline fees for the Hopewell Pipeline during the
year ended
December 31, 2013
. The Hopewell Pipeline contributed
$0.4 million
to net sales and a net loss of
$0.5 million
for the
year ended
December 31, 2013
. The maintenance required to return the Hopewell Pipeline to service and thereby connect it to the Big Sandy Pipeline was completed in the fourth quarter 2013.
Below are the unaudited pro forma consolidated results of operations for the years ended
December 31, 2013
and
2012
, as if these acquisitions had occurred on January 1,
2012
(in thousands):
|
Year Ended December 31,
|
||||||||
|
2013
|
2012
|
|||||||
|
Net sales
|
$
|
908,382
|
|
$
|
1,023,540
|
|
||
|
Net income
|
$
|
41,291
|
|
$
|
25,132
|
|
||
Big Sandy Acquisition
On February 7, 2012, Delek Marketing-Big Sandy, LLC purchased (i) a light petroleum products terminal located in Big Sandy, Texas, the underlying real property, and other related assets from Sunoco Partners Marketing & Terminals L.P. and (ii) the 19-mile, eight-inch diameter Hopewell - Big Sandy Pipeline originating at Hopewell Junction, Texas and terminating at the Big Sandy Station in Big Sandy, Texas from Sunoco Pipeline L.P (collectively "Big Sandy"). The aggregate purchase price was approximately
$11.0 million
. Big Sandy has previously been supplied by the Tyler Refinery but has been idle since November 2008. Big Sandy was contributed to the Partnership as part of the Offering.
The allocation of the aggregate purchase price of Big Sandy as of
December 31, 2013
is summarized as follows (in thousands):
|
Property, plant and equipment
|
$
|
8,258
|
|
|
Intangible assets
|
1,229
|
|
|
|
Goodwill (all expected to be deductible for tax purposes)
|
1,540
|
|
|
|
Total
|
$
|
11,027
|
|
Nettleton Acquisition
On
January 31, 2012
, Delek Crude Logistics, LLC completed the acquisition of an approximately 35-mile long, eight- and ten-inch pipeline system (the "Nettleton Pipeline") from Plains Marketing, L.P. (“Plains”). The purchase price was approximately
$12.3 million
. The Nettleton Pipeline is used exclusively to transport crude oil from our tank farms in and around Longview, Texas to the Bullard Junction at the Tyler Refinery. During the year ended
December 31, 2013
, more than half of the crude oil processed at the Tyler Refinery was supplied through the Nettleton Pipeline. The remainder of the crude oil was supplied through the McMurrey Pipeline, which also begins at our tank farms in and around Nettleton, Texas and then runs roughly parallel to the Nettleton Pipeline. Prior to the acquisition of the Nettleton Pipeline, Delek leased the Nettleton Pipeline from Plains under the terms of the Pipeline Capacity Lease Agreement dated April 12, 1999, as amended (the “Plains Lease”). The Plains Lease was terminated in connection with the acquisition of the Nettleton Pipeline. The Nettleton Pipeline was contributed to the Partnership as part of the Offering.
The allocation of the aggregate purchase price of the Nettleton Pipeline as of
December 31, 2013
is summarized as follows (in thousands):
|
Property, plant and equipment
|
$
|
8,590
|
|
|
Intangible assets
|
2,240
|
|
|
|
Goodwill (all expected to be deductible for tax purposes)
|
1,415
|
|
|
|
Total
|
$
|
12,245
|
|
F-18
Pro Forma Financial Information - Nettleton and the Big Sandy Terminal
We began consolidating the results of operations of the Nettleton Pipeline and Big Sandy on January 31, 2012 and February 7, 2012, respectively. The Nettleton Pipeline contributed
$9.0 million
and
$7.2 million
to net sales and net income, respectively, for the year ended
December 31, 2013
. Big Sandy contributed
$1.5 million
and
$1.2 million
to sales and net income, respectively, for the year ended
December 31, 2013
. Below are the pro forma consolidated results of operations of the Predecessor for the year ended
December 31, 2012
, as if these acquisitions had occurred on January 1, 2012 (amounts in thousands):
|
Year Ended December 31,
|
||||
|
2012
|
||||
|
Net sales
|
$
|
1,022,715
|
|
|
|
Net income
|
$
|
24,941
|
|
|
4
. Net Income Per Unit
We use the two-class method when calculating the net income per unit applicable to limited partners because we have more than one participating security. The two-class method is based on the weighted-average number of common units outstanding during the period. Basic net income per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income, after deducting the general partner’s
2%
interest and incentive distributions, if any, by the weighted-average number of outstanding common and subordinated units. Our net income is allocated to our general partner and limited partners in accordance with their respective partnership percentages after giving effect to priority income allocations for incentive distributions, if any, to our general partner, which is the holder of the incentive distribution rights, pursuant to our partnership agreement, which are declared and paid following the close of each quarter.
Net income per unit is only calculated for periods after the Offering as no units were outstanding prior to November 7, 2012. Earnings in excess of distributions are allocated to our general partner and limited partners based on their respective ownership interests. Payments made to our unitholders are determined in relation to actual distributions declared and are not based on the net income allocations used in the calculation of net income per unit. The basic weighted-average number of units outstanding for the year ended
December 31, 2013
increased to
24,514,527
units from
24,503,469
units in the third quarter
2013
.
Diluted net income per unit applicable to common limited partners includes the effects of potentially dilutive units on our common units. At present, the only potentially dilutive units outstanding consist of unvested phantom units. Basic and diluted net income per unit applicable to subordinated limited partners are the same because there are no potentially dilutive subordinated units outstanding.
F-19
Our distributions are declared subsequent to quarter end. Therefore, the table represents total cash distributions applicable to the period in which the distributions are earned. The calculation of net income per unit is as follows (dollars in thousands, except per unit amounts):
|
Year Ended December 31,
|
||||||||
|
2013
|
2012
|
|||||||
|
Net income attributable to partners
|
$
|
47,830
|
|
$
|
8,410
|
|
||
|
Less: General partner's distribution
|
785
|
|
110
|
|
||||
|
Less: Limited partners' distribution
|
19,292
|
|
2,688
|
|
||||
|
Less: Subordinated partner's distribution
|
19,199
|
|
2,688
|
|
||||
|
Earnings in excess of distributions
|
$
|
8,554
|
|
$
|
2,924
|
|
||
|
General partner's earnings:
|
||||||||
|
Distributions
|
$
|
785
|
|
$
|
110
|
|
||
|
Allocation of earnings in excess of distributions
|
172
|
|
58
|
|
||||
|
Total general partner's earnings
|
$
|
957
|
|
$
|
168
|
|
||
|
Limited partners' earnings on common units:
|
||||||||
|
Distributions
|
$
|
19,292
|
|
$
|
2,688
|
|
||
|
Allocation of earnings in excess of distributions
|
4,198
|
|
1,433
|
|
||||
|
Total limited partners' earnings on common units
|
$
|
23,490
|
|
$
|
4,121
|
|
||
|
Limited partners' earnings on subordinated units:
|
||||||||
|
Distributions
|
$
|
19,199
|
|
$
|
2,688
|
|
||
|
Allocation of earnings in excess of distributions
|
4,184
|
|
1,433
|
|
||||
|
Total limited partner's earnings on subordinated units
|
$
|
23,383
|
|
$
|
4,121
|
|
||
|
Weighted average limited partner units outstanding:
|
||||||||
|
Common units - (basic)
|
12,025,249
|
|
11,999,258
|
|
||||
|
Common units - (diluted)
|
12,148,774
|
|
11,999,258
|
|
||||
|
Subordinated units - Delek (basic and diluted)
|
11,999,258
|
|
11,999,258
|
|
||||
|
Net income per limited partner unit:
|
||||||||
|
Common - (basic)
|
$
|
1.95
|
|
$
|
0.34
|
|
||
|
Common - (diluted)
|
$
|
1.93
|
|
$
|
0.34
|
|
||
|
Subordinated - (basic and diluted)
|
$
|
1.95
|
|
$
|
0.34
|
|
||
F-20
5
. Major Customers
One customer, Susser Petroleum Company ("Susser"), accounted for more than
10%
of consolidated net sales for the year ended
December 31, 2013
. The amount of revenues from Susser during the year ended
December 31, 2013
were $
160.8 million
, which represented
17.7%
of our total consolidated net sales and
19.0%
of our total net sales in our wholesale marketing and terminalling segment. Delek accounted for
84.2%
of our total net sales in our pipelines and transportation segment during the year ended
December 31, 2013
.
Two customers accounted for more than
10%
of consolidated net sales for the years ended
December 31, 2012
and
2011
. During the year ended
December 31, 2012
, Delek accounted for
20.9%
and Susser accounted for
17.5%
of our total revenues, respectively, in our wholesale marketing and terminalling segment. Delek accounted for
88.7%
our our revenues in our pipelines and transportation segment during the year ended
December 31, 2012
. The amount of revenues from Susser were $
178.9 million
and $
154.6 million
for the years ended
December 31, 2012
and
2011
respectively, and are included in our wholesale marketing and terminalling segment. The amount of revenues from Delek were
$236.7 million
and
$27.8 million
for the years ended
December 31, 2012
and
2011
, respectively.
We believe that gross margin is a better measure of performance of our business than revenue, particularly in our wholesale marketing and terminalling segment, as total revenue varies with the price of the underlying product, such as a gallon of finished product. Accordingly, we believe that, for the purpose of evaluating our business on a customer-specific basis, gross margin, which we define as net sales less cost of goods sold, is a more accurate indicator to reflect the importance of certain customers to our operations.
Delek accounted for
72.2%
and
84.0%
of our gross margin in our wholesale marketing and terminalling segment and our pipelines and transportation segment, respectively, in the year ended
December 31, 2013
. Delek accounted for
51.2%
and
57.3%
of our Predecessor's gross margin in our wholesale and terminalling segment in the years ended
December 31, 2012
and
2011
, respectively, and for
88.7%
and
46.0%
of our gross margin in our pipelines and transportation segment, in the years ended
December 31, 2012
and
2011
, respectively.
6
. Inventory
Inventory consists of refined products which are stated at the lower of cost or market on a first-in, first-out ("FIFO") basis. Carrying value of inventories consisted of
$17.5 million
and
$14.4 million
of refined petroleum products as of
December 31, 2013
and
December 31, 2012
, respectively.
7
. Property, Plant and Equipment
Property, plant and equipment, at cost, consist of the following (in thousands):
|
December 31,
|
||||||||
|
2013
|
2012
|
|||||||
|
Land and land improvements
|
$
|
1,931
|
|
$
|
1,084
|
|
||
|
Building and building improvements
|
944
|
|
923
|
|
||||
|
Pipelines and terminals
|
205,866
|
|
175,456
|
|
||||
|
Asset retirement obligations
|
1,999
|
|
1,998
|
|
||||
|
Other equipment
|
2,219
|
|
1,557
|
|
||||
|
Construction in process
|
22,629
|
|
35,030
|
|
||||
|
235,588
|
|
216,048
|
|
|||||
|
Less: accumulated depreciation
|
(36,306
|
)
|
(24,991
|
)
|
||||
|
$
|
199,282
|
|
$
|
191,057
|
|
|||
Property, plant and equipment, accumulated depreciation and depreciation expense by reporting segment as of and for the years ended
December 31, 2013
and
2012
are as follows (in thousands):
|
As of and For the Year Ended December 31, 2013
|
||||||||||||
|
Pipelines and Transportation
|
Wholesale Marketing and Terminalling
|
Consolidated
|
||||||||||
|
Property, plant and equipment
|
$
|
174,823
|
|
$
|
60,765
|
|
$
|
235,588
|
|
|||
|
Less: Accumulated depreciation
|
(22,032
|
)
|
(14,274
|
)
|
(36,306
|
)
|
||||||
|
Property, plant and equipment, net
|
$
|
152,791
|
|
$
|
46,491
|
|
$
|
199,282
|
|
|||
|
Depreciation expense
|
$
|
8,756
|
|
$
|
2,617
|
|
$
|
11,373
|
|
|||
F-21
|
As of and For the Year Ended December 31, 2012
|
||||||||||||
|
Pipelines and Transportation
|
Wholesale Marketing and Terminalling
|
Consolidated
|
||||||||||
|
Property, plant and equipment
|
$
|
168,196
|
|
$
|
47,852
|
|
$
|
216,048
|
|
|||
|
Less: Accumulated depreciation
|
(13,642
|
)
|
(11,349
|
)
|
(24,991
|
)
|
||||||
|
Property, plant and equipment, net
|
$
|
154,554
|
|
$
|
36,503
|
|
$
|
191,057
|
|
|||
|
Depreciation expense
|
$
|
6,771
|
|
$
|
2,285
|
|
$
|
9,056
|
|
|||
8
. Goodwill
Goodwill represents the excess of the aggregate purchase price over the fair value of the identifiable net assets acquired. Goodwill acquired in a purchase business combination is recorded at fair value and is not amortized. Our goodwill relates to the west Texas assets contributed to us by Delek Marketing in connection with the Offering and to the allocation of the purchase price of our Nettleton and Big Sandy acquisitions that occurred in January 2012 and February 2012, respectively.
We perform an annual assessment of whether goodwill retains its value. This assessment is done more frequently if indicators of potential impairment exist. We performed our annual goodwill impairment review in the fourth quarter of
2013
,
2012
and
2011
. We performed a discounted cash flows test, using a market participant weighted average cost of capital, and estimated minimal growth rates for revenue, gross profit, and capital expenditures based on history and our best estimate of future forecasts. We also estimated the fair values using a multiple of expected future cash flows such as those used by third party analysts. In
2013
,
2012
and
2011
the annual impairment review resulted in the determination that no impairment of goodwill had occurred. Goodwill was
$10.5 million
at
December 31, 2013
.
A summary of our goodwill accounts is as follows (in thousands):
|
Balance,
|
December 31, 2010
|
$
|
7,499
|
|
|
|
Goodwill impairment
|
—
|
|
|||
|
Balance,
|
December 31, 2011
|
7,499
|
|
||
|
Goodwill impairment
|
—
|
|
|||
|
Goodwill acquired through the business combinations of Nettleton and Big Sandy
|
2,955
|
|
|||
|
Balance,
|
December 31, 2012
|
10,454
|
|
||
|
Goodwill impairment
|
—
|
|
|||
|
Balance,
|
December 31, 2013
|
$
|
10,454
|
|
|
9
. Other Intangible Assets
Our identifiable intangible assets are are as follows (in thousands):
|
Useful
|
Accumulated
|
|||||||||||||
|
As of December 31, 2013
|
Life
|
Gross
|
Amortization
|
Net
|
||||||||||
|
Intangible assets subject to amortization:
|
||||||||||||||
|
Supply contracts
|
11.5
|
$
|
12,227
|
|
$
|
(7,885
|
)
|
$
|
4,342
|
|
||||
|
Intangible assets not subject to amortization:
|
||||||||||||||
|
Rights-of-way assets
|
Indefinite
|
7,916
|
|
—
|
|
7,916
|
|
|||||||
|
Total
|
$
|
20,143
|
|
$
|
(7,885
|
)
|
$
|
12,258
|
|
|||||
F-22
|
Useful
|
Accumulated
|
|||||||||||||
|
As of December 31, 2012
|
Life
|
Gross
|
Amortization
|
Net
|
||||||||||
|
Intangible assets subject to amortization:
|
||||||||||||||
|
Supply contracts
|
11.5
|
$
|
12,227
|
|
$
|
(6,822
|
)
|
$
|
5,405
|
|
||||
|
Intangible assets not subject to amortization:
|
||||||||||||||
|
Rights-of-way assets
|
Indefinite
|
7,025
|
|
—
|
|
7,025
|
|
|||||||
|
Total
|
$
|
19,252
|
|
|
$
|
(6,822
|
)
|
$
|
12,430
|
|
||||
Amortization of intangible assets was
$1.1 million
, during each of the years ended
December 31, 2013
,
2012
and
2011
and is included in depreciation and amortization on the accompanying consolidated statements of operations. Amortization expense is estimated to be
$1.1 million
per year for the years ended 2014 through 2017.
10
. Long-Term Obligations
Amended and Restated Credit Agreement
On July 9, 2013, we amended and restated our senior secured revolving credit agreement, which we originally entered into on November 7, 2012, with Fifth Third Bank, as administrative agent, and a syndicate of lenders, (the "Amended and Restated Credit Agreement"). Under the terms of the Amended and Restated Credit Agreement, the lender commitments were increased from
$175.0 million
to
$400.0 million
and a dual currency borrowing tranche was added that permits draw downs in U.S. or Canadian dollars. The Amended and Restated Credit Agreement also contains an accordion feature whereby the Partnership can increase the size of the credit facility to an aggregate of
$450.0 million
, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. The Amended and Restated Credit Agreement matures on
November 7, 2017
.
Borrowings denominated in U.S. dollars under the Amended and Restated Credit Agreement bear interest at either a U.S. dollar prime rate, plus an applicable margin, or the London Interbank Offered Rate ("LIBOR"), plus an applicable margin, at the election of the borrowers. Borrowings denominated in Canadian dollars under the Amended and Restated Credit Agreement bear interest at either a Canadian dollar prime rate, plus an applicable margin, or Canadian Dealer Offered Rate ("CDOR"), plus an applicable margin, at the election of the borrowers. The applicable margin in each case varies based upon the Partnership's most recently reported leverage ratio. At
December 31, 2013
, the weighted average interest rate was approximately
2.5%
. Additionally, the Amended and Restated Credit Facility requires us to pay a leverage ratio dependent quarterly fee on the average unused revolving commitment. As of
December 31, 2013
, this fee was
0.40%
per year.
The obligations under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of the Partnership's and its U.S. subsidiaries' tangible and intangible assets. Additionally, Delek Marketing provides a limited guaranty of the Partnership's obligations under the Amended and Restated Credit Agreement. Delek Marketing's guaranty is (i) limited to an amount equal to the principal amount, plus unpaid and accrued interest, of a promissory note made by Delek US in favor of Delek Marketing (the "Holdings Note") and (ii) secured by Delek Marketing's pledge of the Holdings Note to our lenders under the Amended and Restated Credit Agreement. As of
December 31, 2013
, the principal amount of the Holdings Note was
$102.0 million
, plus unpaid interest accrued since the issuance date.
As of
December 31, 2013
, we had
$164.8 million
outstanding borrowings under the Amended and Restated Credit Agreement. Additionally, we had in place letters of credit totaling
$12.0 million
with Fifth Third bank, primarily securing obligations with respect to gasoline and diesel purchases. No amounts were drawn by beneficiaries of these letters of credit at
December 31, 2013
. Amounts available under the Amended and Restated Credit Agreement as of
December 31, 2013
were approximately
$223.2 million
.
Principal maturities of the Partnership's existing third party debt instruments for the next five years and thereafter are as follows as of
December 31, 2013
(in thousands):
|
2014
|
2015
|
2016
|
2017
|
2018
|
Thereafter
|
Total
|
|||||||||||||||||
|
Amended and Restated Credit Agreement
|
—
|
|
—
|
|
—
|
|
$
|
164,800
|
|
—
|
|
—
|
|
$
|
164,800
|
|
|||||||
11
. Equity
We had
9,353,240
common limited partner units held by the public outstanding as of
December 31, 2013
. Additionally, as of
December 31, 2013
, Delek owned a
60.0%
limited partner interest in us, consisting of
2,799,258
common limited partner units and
11,999,258
subordinated limited partner units as well as a
96.6%
interest in our general partner, which owns the entire
F-23
2.0%
general partner interest consisting of
492,893
general partner units. In accordance with our partnership agreement, Delek's subordinated units may convert to common units once specified distribution targets and other requirements have been met.
The table below summarizes the changes in the number of units outstanding through
December 31, 2013
(in units). There were no units outstanding prior to our initial public offering in November 2012.
|
Common - Public
|
Common - Delek
|
Subordinated
|
General Partner
|
Total
|
|||||||||||
|
Units issued in initial public offering in November 2012
|
9,200,000
|
|
2,799,258
|
|
11,999,258
|
|
489,766
|
|
24,488,282
|
|
|||||
|
Balance at December 31, 2012
|
9,200,000
|
|
2,799,258
|
|
11,999,258
|
|
489,766
|
|
24,488,282
|
|
|||||
|
GP units issued to maintain 2% interest
|
—
|
|
—
|
|
—
|
|
3,127
|
|
3,127
|
|
|||||
|
Unit-based compensation awards
(1)
|
153,240
|
|
—
|
|
—
|
|
—
|
|
153,240
|
|
|||||
|
Balance at December 31, 2013
|
9,353,240
|
|
2,799,258
|
|
11,999,258
|
|
492,893
|
|
24,644,649
|
|
|||||
(1)
Unit-based compensation awards are presented net of
31,083
units withheld for taxes.
Issuance of Additional Securities
Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders. Costs associated with the issuance of securities are allocated to all unitholders' capital accounts based on their ownership interest at the time of issuance.
Allocations of Net Income
Our partnership agreement contains provisions for the allocation of net income and loss to the unitholders and our general partner. For purposes of maintaining partner capital accounts, the partnership agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interest. Normal allocations according to percentage interests are made after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions allocated 100% to our general partner.
The calculation of net income allocated to the partners is as follows (in thousands, except per unit amounts):
|
Year Ended December 31,
|
||||||||
|
2013
|
2012
|
|||||||
|
Net income attributable to partners
|
$
|
47,830
|
|
$
|
8,410
|
|
||
|
General partner's ownership interest
|
2.0
|
%
|
2.0
|
%
|
||||
|
Less: General partner's allocated interest in net income
|
957
|
|
168
|
|
||||
|
Limited partners' interest in net income:
|
46,873
|
|
8,242
|
|
||||
|
Limited partners' allocated interest in net income - (common)
|
$
|
23,490
|
|
$
|
4,121
|
|
||
|
Limited partners' allocated interest in net income - (subordinated)
|
$
|
23,383
|
|
$
|
4,121
|
|
||
Percentage Allocations of Available Cash from Operating Surplus
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its
2.0%
general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.
F-24
|
Total Quarterly
|
Marginal Percentage
|
|||||||
|
Distribution per Unit
|
Interest in Distributions
|
|||||||
|
Target Amount
|
Unitholders
|
General Partner
|
||||||
|
Minimum quarterly distribution
|
$0.37500
|
98.0
|
%
|
2.0
|
%
|
|||
|
First target distribution
|
above $0.37500 up to $0.43125
|
98.0
|
%
|
2.0
|
%
|
|||
|
Second target distribution
|
above $0.43125 up to $0.46875
|
85.0
|
%
|
15.0
|
%
|
|||
|
Third target distribution
|
above $0.46875 up to $0.56250
|
75.0
|
%
|
25.0
|
%
|
|||
|
Thereafter
|
above $0.56250
|
50.0
|
%
|
50.0
|
%
|
|||
Cash distributions
Our partnership agreement sets forth the calculation to be used to determine the amount and priority of the minimum cash distributions that the common and subordinated unitholders and general partner will receive. Our minimum quarterly distributions are declared subsequent to quarter end. The table below summarizes the minimum quarterly distributions related to our quarterly financial results:
|
Quarter Ended
|
Total Quarterly Distribution Per Unit
|
Total Quarterly Distribution Per Unit, Annualized
|
Total Cash Distribution (in thousands)
|
Date of Distribution
|
Unitholders Record Date
|
|||||
|
December 31, 2013
|
$0.415
|
$1.66
|
$10,228
|
February 13, 2014
|
February 4, 2014
|
|||||
|
September 30, 2013
|
$0.405
|
$1.62
|
$9,933
|
November 14, 2013
|
November 7, 2013
|
|||||
|
June 30, 2013
|
$0.395
|
$1.58
|
$9,687
|
August 13, 2013
|
August 6, 2013
|
|||||
|
March 31, 2013
|
$0.385
|
$1.54
|
$9,428
|
May 15, 2013
|
May 7, 2013
|
|||||
|
December 31, 2012 (from November 7, 2012)
(1)
|
$0.224
|
$0.90
|
$5,486
|
February 14, 2013
|
February 6, 2013
|
|||||
(1)
The quarterly cash distribution for the three months ended December 31, 2012 was calculated as the minimum quarterly cash distribution of
$0.375
per unit per quarter, or
$1.50
per unit on an annualized basis, prorated for the period beginning November 7, 2012, the date the Partnership commenced operations.
The allocation of total quarterly cash distributions to general and limited partners is as follows for the years ended
December 31, 2013
and
2012
. Our distributions are declared subsequent to quarter end. Therefore, the table below represents total cash distributions applicable to the period in which the distributions are earned (in thousands, except per unit amounts):
|
Year Ended December 31,
|
||||||||
|
2013
|
2012
|
|||||||
|
General partner's distributions
|
$
|
785
|
|
$
|
110
|
|
||
|
Limited partners' distributions:
|
||||||||
|
Common
|
19,292
|
|
2,688
|
|
||||
|
Subordinated
|
19,199
|
|
2,688
|
|
||||
|
Total cash distributions
|
$
|
39,276
|
|
$
|
5,486
|
|
||
|
Cash distributions per unit
|
$
|
1.600
|
|
$
|
0.224
|
|
||
12
. Equity Based Compensation
The Delek Logistics GP, LLC 2012 Long-Term Incentive Plan (the "LTIP") was adopted by the Delek Logistics GP, LLC Board of Directors in connection with the completion of the Offering in November 2012. The LTIP provides for officers, directors and employees of our general partner or its affiliates, and any consultants, affiliates of our general partner or other
F-25
individuals who perform services for us. The LTIP consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The LTIP limits the number of common units that may be delivered pursuant to awards under the plan to
612,207
units. The LTIP is administered by the Conflicts Committee of the Board of Directors of our general partner.
We incurred approximately
$0.5 million
of unit-based compensation expense related to the Partnership during the year ended
December 31, 2013
. The fair value of our phantom units is determined based on the closing price of our common limited partner units on the grant date. The estimated fair value of our phantom units is amortized over the vesting period using the straight line method. Awards vest over a five-year service period. The total fair value of phantom units vested during the year ended
December 31, 2013
was
$4.2 million
. No phantom units vested during the years ended
December 31, 2012
and
2011
. As of
December 31, 2013
, there was
$0.8 million
of total unrecognized compensation cost related to non-vested equity-based compensation arrangements, which is expected to be recognized over a weighted-average period of
4
.0 years. A summary of our unit award activity for the twelve months ended
December 31, 2013
is set forth below:
|
Number of Phantom Units
|
Weighted-Average Grant Price
|
||||||
|
Non-vested
|
January 1, 2013
|
494,883
|
|
$
|
22.65
|
|
|
|
Granted
|
7,500
|
|
$
|
34.12
|
|
||
|
Vested
|
184,323
|
|
$
|
22.68
|
|
||
|
Forfeited
|
43,108
|
|
$
|
22.65
|
|
||
|
Non-vested
|
December 31, 2013
|
274,952
|
|
$
|
22.94
|
|
|
Sponsor's Equity-Based Compensation
Certain employees supporting the DKL Predecessor's operations received long-term incentive compensation that is part of the Delek US Holdings, Inc. 2006 Long-Term Incentive Plan, as amended (the “2006 Plan”). The 2006 Plan allows Delek to grant stock options, stock appreciation rights ("SARs"), restricted stock units and other stock-based awards denominated in shares of Delek's common stock to certain directors, officers, employees, consultants and other individuals who perform services for Delek or its affiliates, including these employees. Delek uses the Black-Scholes-Merton option-pricing model to determine the fair value of stock option and SAR awards, with the exception of the SARs granted to certain executive employees, which are valued under the Monte-Carlo simulation model. Restricted stock units are measured based on the fair market value of the underlying stock on the date of grant. Compensation expense related to stock-based awards is generally recognized with graded or cliff vesting on a straight-line basis over the vesting period.
Certain Delek employees supporting the DKL Predecessor's operations were historically granted these types of awards. These costs were recorded as compensation expense and additional paid-in capital and totaled
$0.1 million
related to the DKL Predecessor's employees for the years ended
December 31, 2012
and
2011
. The DKL Predecessor recognized additional compensation expense related to equity-based compensation awards to related party employees of
$0.5 million
for both the years ended
December 31, 2012
, and
2011
for allocated related party services and an allocation of director and executive officer equity-based compensation.
As of
December 31, 2012
, there was no unrecognized compensation cost related to non-vested equity-based compensation arrangements for the DKL Predecessor's employees. Subsequent to the Offering, these costs are allocated to the Partnership as part of the administrative fee under the Omnibus Agreement (as defined in
Note 18
—Related Party Transactions).
13
. Segment Data
We report our assets and operating results in two reportable segments: (i) pipelines and transportation and (ii) wholesale marketing and terminalling.
|
•
|
The pipelines and transportation segment provides crude oil gathering, transportation and storage services to Delek's refining operations and independent third parties.
|
|
•
|
The wholesale marketing and terminalling segment provides marketing and terminalling services to Delek's refining operations and independent third parties.
|
Our operating segments adhere to the accounting polices used for our consolidated financial statements, as described in
Note 1
. Our operating segments are managed separately because each segment requires different industry knowledge, technology and marketing strategies. Decisions concerning the allocation of resources and assessment of operating performance are made based on this segmentation. Management measures the operating performance of each of its reportable segments based on the segment contribution margin. Segment contribution margin is defined as net sales less cost of sales and operating expenses, excluding depreciation and amortization.
On July 26, 2013, we acquired the Tyler Terminal and Tank Assets from Delek. Our and our Predecessors' historical financial statements have been retrospectively adjusted to reflect the results of operations attributable to the Tyler Terminal and Tank Assets as if we owned the assets for all periods presented. The results of the Tyler Terminal and the Tyler Tank Assets are included in the wholesale marketing and terminalling segment and the pipelines and transportation segment, respectively.
F-26
The following is a summary of business segment operating performance as measured by contribution margin for the period indicated (in thousands):
|
|
As of and For the Year Ended December 31, 2013
(1)
|
|||||||||||
|
(In thousands)
|
Pipelines and Transportation
|
Wholesale Marketing and Terminalling
|
Consolidated
|
|||||||||
|
Net sales (excluding intercompany fees and sales)
|
$
|
60,237
|
|
$
|
847,191
|
|
$
|
907,428
|
|
|||
|
Operating costs and expenses:
|
|
|
||||||||||
|
Cost of goods sold
|
764
|
|
810,600
|
|
811,364
|
|
||||||
|
Operating expenses
|
22,903
|
|
7,399
|
|
30,302
|
|
||||||
|
Segment contribution margin
|
$
|
36,570
|
|
$
|
29,192
|
|
65,762
|
|
||||
|
General and administrative expenses
|
|
6,856
|
|
|||||||||
|
Depreciation and amortization
|
|
12,436
|
|
|||||||||
|
Loss on disposal of assets
|
|
166
|
|
|||||||||
|
Operating income
|
|
$
|
46,304
|
|
||||||||
|
Total assets
|
$
|
164,608
|
|
$
|
110,196
|
|
$
|
274,804
|
|
|||
|
Capital spending (excluding business combinations)
(2)
|
$
|
6,905
|
|
$
|
2,493
|
|
$
|
9,398
|
|
|||
(1)
The information presented includes the results of operations of the Tyler Predecessor. Prior to the completion of the Tyler Acquisition, our Predecessor did not record revenues for intercompany gathering, pipeline transportation, terminalling and storage services.
(2)
Capital
spending includes expenditures incurred in connection with the assets acquired in the Tyler Acquisition
|
|
As of and For the Year Ended December 31, 2012
(1)
|
|||||||||||
|
Predecessors
|
||||||||||||
|
(In thousands)
|
Pipelines and Transportation
|
Wholesale Marketing and Terminalling
|
Consolidated
|
|||||||||
|
Net sales (excluding intercompany fees and sales)
|
$
|
33,539
|
|
$
|
989,047
|
|
$
|
1,022,586
|
|
|||
|
Operating costs and expenses:
|
|
|
|
|||||||||
|
Cost of goods sold
|
—
|
|
959,434
|
|
959,434
|
|
||||||
|
Operating expenses
|
24,155
|
|
6,242
|
|
30,397
|
|
||||||
|
Segment contribution margin
|
$
|
9,384
|
|
$
|
23,371
|
|
32,755
|
|
||||
|
General and administrative expenses
|
|
|
9,150
|
|
||||||||
|
Depreciation and amortization
|
|
|
10,120
|
|
||||||||
|
Loss on disposal of assets
|
|
|
9
|
|
||||||||
|
Operating income
|
|
|
$
|
13,476
|
|
|||||||
|
Total assets
|
$
|
183,204
|
|
$
|
100,112
|
|
$
|
283,316
|
|
|||
|
Capital spending (excluding business combinations)
(2)
|
$
|
22,146
|
|
$
|
4,613
|
|
$
|
26,759
|
|
|||
|
(1)
|
The
information presented is adjusted to include the results of operations of the Tyler Predecessor. Prior to the completion of the Offering and the Tyler Acquisition, our Predecessors did not record revenues for intercompany trucking, terminalling, storage and short-haul pipeline transportation services.
|
|
(2)
|
Capital
spending includes expenditures incurred in connection with the assets acquired in the Tyler Acquisition.
|
F-27
|
|
As of and For the Year Ended December 31, 2011
(1)
|
|||||||||||
|
Predecessors
|
||||||||||||
|
(In thousands)
|
Pipelines and Transportation
(2)
|
Wholesale Marketing and Terminalling
|
Consolidated
|
|||||||||
|
Net sales (excluding intercompany fees and sales)
|
$
|
21,878
|
|
$
|
722,201
|
|
$
|
744,079
|
|
|||
|
Operating costs and expenses:
|
|
|
|
|||||||||
|
Cost of goods sold
|
—
|
|
700,505
|
|
700,505
|
|
||||||
|
Operating expenses
|
15,415
|
|
4,052
|
|
19,467
|
|
||||||
|
Segment contribution margin
|
$
|
6,463
|
|
$
|
17,644
|
|
24,107
|
|
||||
|
General and administrative expenses
|
|
|
6,483
|
|
||||||||
|
Depreciation and amortization
|
|
|
6,061
|
|
||||||||
|
Gain on disposal of assets
|
(2
|
)
|
||||||||||
|
Operating income
|
|
|
$
|
11,565
|
|
|||||||
|
Total assets
|
$
|
133,257
|
|
$
|
89,902
|
|
$
|
223,159
|
|
|||
|
Capital spending (excluding business combinations)
(3)
|
$
|
5,905
|
|
$
|
1,225
|
|
$
|
7,130
|
|
|||
|
(1)
|
The
information presented is adjusted to include the results of operations of the Tyler Predecessor. Prior to the completion of the Offering and the Tyler Acquisition, our Predecessors did not record revenues for intercompany trucking, terminalling, storage and short-haul pipeline transportation services.
|
|
(2)
|
The operating results presented are for the 247 days and 12 days, respectively, Delek operated the El Dorado Refinery and the Paline Pipeline System in 2011.
|
|
(3)
|
Capital spending includes expenditures incurred in connection with the assets acquired in the Tyler Acquisition.
|
14
. Fair Value Measurements
The fair values of financial instruments are estimated based upon current market conditions and quoted market prices for the same or similar instruments. Management estimates that the carrying value approximates fair value for all of our assets and liabilities that fall under the scope of ASC 825,
Financial Instruments
.
We apply the provisions of ASC 820,
Fair Value Measurements
("ASC 820"), which defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. ASC 820 applies to our interest rate and commodity derivatives that are measured at fair value on a recurring basis. The standard also requires that we assess the impact of nonperformance risk on our derivatives. Nonperformance risk is not considered material at this time.
ASC 820 requires disclosures that categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting our assumptions about pricing by market participants.
Over the counter commodity swaps and sale contracts are generally valued using industry-standard models that consider various assumptions, including quoted forward prices, time value, volatility factors and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines the classification as Level 2 or 3. Our over the counter commodity swaps are valued using quotations provided by brokers based on exchange pricing and/or price index developers such as Platts or Argus. These are classified as Level 2.
The fair value hierarchy for our financial assets accounted for at fair value on a recurring basis was as follows: (in thousands):
|
|
As of December 31, 2013
|
|||||||||||||||
|
|
Level 1
|
Level 2
|
Level 3
|
Total
|
||||||||||||
|
Assets
|
|
|
|
|
||||||||||||
|
Interest rate derivatives
|
$
|
—
|
|
$
|
116
|
|
$
|
—
|
|
$
|
116
|
|
||||
As of
December 31, 2012
, there was a nominal amount of financial liabilities accounted for at fair value on a recurring basis.
The derivative values above are based on analysis of each contract as the fundamental unit of account as required by ASC 820. Derivative assets and liabilities with the same counterparty are not netted where the legal right of offset exists. This differs from the presentation in the financial statements which reflects our policy under the guidance of ASC 815-10-45,
Derivatives and Hedging - Other Presentation Matters
("ASC 815-10-45"), wherein we have elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty where the legal right of offset exists. As of December 31, 2012, a nominal amount of net derivative positions are included in other current assets and other current liabilities, respectively on the accompanying consolidated balance sheets.
Our policy under the guidance of ASC 815-10-45, is to net the fair value amounts recognized for multiple derivative instruments executed with the same counterparty and offset these values against the cash collateral arising from these derivative positions. As of
December 31, 2013
,
no
cash collateral was held by counterparty brokerage firms. As of
December 31, 2012
, a nominal amount of cash collateral was held by counterparty brokerage firms.
F-28
15
. Derivative Instruments
From time to time, we enter into forward fuel contracts to limit the exposure to price fluctuations for physical purchases of finished products in the normal course of business. We use derivatives to reduce normal operating and market risks with a primary objective in derivative instrument use being the reduction of the impact of market price volatility on our results of operations.
We enter into forward fuel contracts with major financial institutions in which we fix the purchase price of finished grade fuel for a predetermined number of units with fulfillment terms of less than 90 days. During the years ended
December 31, 2013
and
2012
, we did not elect hedge accounting treatment for these derivative positions. As a result, all changes in fair value are marked to market in the accompanying consolidated statements of income.
From time to time, we may also enter into interest rate hedging agreements to limit variable interest rate exposure under the Amended and Restated Credit Agreement. The prior credit facility required us to maintain interest rate hedging arrangements on at least 50% of the amount funded on
November 7, 2012
under the credit facility, which was required to be in place for at least a three-year period beginning no later than
March 7, 2013
. Effective
February 25, 2013
, we entered into interest rate hedges in the form of a LIBOR interest rate cap for a term of three years for a total notional amount of
$45.0 million
, thereby meeting the requirements.
The table below presents the fair value of our derivative instruments, as of
December 31, 2013
. As of
December 31, 2012
, there was a nominal amount of financial liabilities accounted for at fair value on a recurring basis (in thousands).
|
December 31, 2013
|
|||||||||
|
Derivative Type
|
Balance Sheet Location
|
Assets
|
Liabilities
|
||||||
|
Derivatives not designated as hedging instruments:
|
|||||||||
|
Interest rate derivatives
|
Other long term assets
|
$
|
116
|
|
$
|
—
|
|
||
Gains (losses) recognized associated with derivatives not designated as hedging instruments for the years ended
December 31, 2013
and
2012
were as follows (in thousands):
|
Year Ended December 31,
|
|||||||||
|
Derivative Type
|
Income Statement Location
|
2013
|
2012
|
||||||
|
Predecessors
|
|||||||||
|
Interest rate derivatives
|
Interest expense
|
(106
|
)
|
—
|
|
||||
|
Commodity derivatives
|
Cost of goods sold
|
(614
|
)
|
85
|
|
||||
|
Total
|
$
|
(720
|
)
|
$
|
85
|
|
|||
There were
no
unrealized gains related to these forward fuel contracts held on the consolidated balance sheets as of
December 31, 2013
and nominal unrealized gains as of
December 31, 2012
.
16
. Income Taxes
Prior to the Offering, the DKL Predecessor was a corporation included in its parent's consolidated tax return. As such, the DKL Predecessor was subject to both federal and state income taxes and recorded deferred income taxes for the differences between the book and tax bases of its assets and liabilities, which are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse.
Effective with the closing of the Offering, the Partnership is no longer a taxable entity for federal income tax purposes. While most states do not impose an entity level tax on partnership income, the Partnership is subject to entity level tax in both Tennessee and Texas. The Partnership does not file a separate Texas income tax return. Our results of operations are included in Delek’s consolidated return. However, the provisions of ASC 740 have been followed as if we were a stand-alone entity.
F-29
As a result, the Partnership must record deferred income taxes for the differences between book and tax bases of its assets and liabilities based on those states' enacted tax rates and laws that will be in effect when the differences are expected to reverse.
The Partnership had a tax benefit of
$14.0 million
for the year ended
December 31, 2012
. For the period subsequent to the Offering, the Partnership had total tax expense of
$0.1 million
in
2012
. The majority of the change in deferred tax assets and liabilities relates to the DKL Predecessor's conversion from a corporation to a partnership and no longer being subject to federal income tax. The conversion from a taxable corporation to a passthrough resulted in a one-time tax benefit of
$18.5 million
in
2012
.
Significant components of our deferred tax assets and liabilities, reported separately in the accompanying combined financial statements, as of
December 31, 2013
and
2012
, are as follows (in thousands):
|
December 31,
|
||||||||
|
2013
|
2012
|
|||||||
|
Current Deferred Taxes:
|
||||||||
|
Accrued reserves
|
$
|
6
|
|
$
|
1
|
|
||
|
Tank and pipeline inspection liabilities
|
8
|
|
2
|
|
||||
|
Contingent liabilities
|
—
|
|
11
|
|
||||
|
Depreciation and amortization
|
(2
|
)
|
—
|
|
||||
|
Total current deferred tax assets
|
12
|
|
14
|
|
||||
|
Non-Current Deferred Taxes:
|
||||||||
|
Depreciation and amortization
|
(370
|
)
|
(36
|
)
|
||||
|
Asset retirement obligations
|
4
|
|
1
|
|
||||
|
Tank and pipeline inspection liabilities
|
30
|
|
6
|
|
||||
|
Contingent liabilities
|
12
|
|
13
|
|
||||
|
Other
|
—
|
|
(1
|
)
|
||||
|
Total non-current deferred tax liabilities
|
(324
|
)
|
(17
|
)
|
||||
|
Total net deferred tax liabilities
|
$
|
(312
|
)
|
$
|
(3
|
)
|
||
The total current deferred tax assets and liabilities, respectively, excluding the valuation allowance, were nominal as of
December 31, 2013
and
December 31, 2012
. The total non-current deferred tax assets and liabilities, respectively, excluding the valuation allowance, were nominal and
$0.4 million
as of
December 31, 2013
and nominal as of
December 31, 2012
.
The difference between the actual income tax expense and the tax expense computed by applying the statutory federal income tax rate to income before income taxes is attributable to the following (in thousands):
|
Year Ended December 31,
|
||||||||||||
|
2013
|
2012
|
2011
|
||||||||||
|
Provision for federal income taxes at statutory rate
|
$
|
—
|
|
$
|
4,047
|
|
$
|
6,304
|
|
|||
|
State income taxes, net of federal tax provision
|
794
|
|
(58
|
)
|
255
|
|
||||||
|
Valuation allowance
|
—
|
|
193
|
|
(1,145
|
)
|
||||||
|
Permanent differences
|
—
|
|
300
|
|
15
|
|
||||||
|
Conversion to partnership
|
—
|
|
(18,534
|
)
|
—
|
|
||||||
|
Other items
|
(37
|
)
|
28
|
|
(66
|
)
|
||||||
|
Income tax (benefit) expense
|
$
|
757
|
|
$
|
(14,024
|
)
|
$
|
5,363
|
|
|||
F-30
Income tax expense (benefit) is as follows (in thousands):
|
Year Ended December 31,
|
||||||||||||
|
2013
|
2012
|
2011
|
||||||||||
|
Current
|
$
|
448
|
|
$
|
4,738
|
|
$
|
9,691
|
|
|||
|
Deferred
|
309
|
|
(18,762
|
)
|
(4,328
|
)
|
||||||
|
$
|
757
|
|
$
|
(14,024
|
)
|
$
|
5,363
|
|
||||
Deferred income tax expense above is reflective of the changes in deferred tax assets and liabilities during the current period.
Delek US files a consolidated Texas income tax return and current income tax payments for DKL are paid by Delek US. Therefore, any current income tax payable is included in accounts receivable/payable from related parties. As of
December 31, 2013
and
2012
, income taxes payable of
$0.4 million
and a nominal amount, respectively, were included in accounts receivable/payable from related parties in the accompanying consolidated balance sheets. Taxes that are determined on a combined basis apply the “benefits for loss” allocation method; thus, tax attributes are realized when used in the combined tax return to the extent that they have been subject to a valuation allowance.
We recognize accrued interest and penalties related to unrecognized tax benefits as an adjustment to the current provision for income taxes. There are no uncertain tax positions recorded as of
December 31, 2013
,
2012
or
2011
and there were no interest or penalties recognized related to uncertain tax positions for the years ended
December 31, 2013
,
2012
or
2011
. We have examined uncertain tax positions for any material changes in the next 12 months and none are expected.
17
. Commitments and Contingencies
Litigation
In the ordinary conduct of our business, we are from time to time subject to lawsuits, investigations and claims, including environmental claims and employee-related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, including civil penalties or other enforcement actions, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.
Rate Regulation of Petroleum Pipelines
The rates and terms and conditions of service on certain of our pipelines are subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act (“ICA”) and by the state regulatory commissions in the states in which we transport crude oil and refined products, including the Railroad Commission of Texas, the Louisiana Public Service Commission, and the Arkansas Public Service Commission. Certain of our pipeline systems are subject to such regulation and have filed tariffs with the FERC. We also comply with the reporting requirements for these pipelines. Other of our pipelines have received a waiver from application of FERC's tariff requirements but will comply with other regulatory requirements.
The FERC regulates interstate transportation under the ICA, the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including pipelines that transport crude oil and refined products in interstate commerce (collectively referred to as “petroleum pipelines”), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with the FERC. Under the ICA, shippers may challenge new or existing rates or services. The FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. Tariff rates are typically contractually subject to increase or decrease on July 1 of each year, beginning on July 1, 2013, by the amount of any change in FERC oil pipeline index or, in the case of the east Texas marketing agreement and the Tyler Throughput and Tankage Agreement, to other inflation based indexes; provided, however, that in no event will the fees be adjusted below the amount initially set forth in the applicable agreement.
While the FERC regulates rates for shipments of crude oil or refined products in interstate commerce, state agencies may regulate rates and service for shipments in intrastate commerce. We own pipeline assets in Texas, Arkansas, and Louisiana.
Environmental Health and Safety
We are subject to various federal, state and local environmental and safety laws enforced by agencies including the U.S. Environmental Protection Agency (the "EPA"), the U.S. Department of Transportation ("DOT") / Pipeline and Hazardous
F-31
Materials Safety Administration, the U.S. Department of Labor / Occupational Safety and Health Administration, the Texas Commission on Environmental Quality, the Texas Railroad Commission, the Arkansas Department of Environmental Quality (the "ADEQ") and the Tennessee Department of Environment and Conservation as well as other state and federal agencies. Numerous permits or other authorizations are required under these laws for the operation of our terminals, pipelines, and related operations, and may be subject to revocation, modification and renewal.
These laws and permits raise potential exposure to future claims and lawsuits involving environmental and safety matters which could include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed, or that relate to pre-existing conditions for which we have assumed responsibility. We believe that our current operations are in substantial compliance with existing environmental and safety requirements. However, there have been and will continue to be ongoing discussions about environmental and safety matters between us and federal and state authorities, including notices of violations, citations and other enforcement actions, some of which have resulted or may result in changes to operating procedures and in capital expenditures. While it is often difficult to quantify future environmental or safety related expenditures, we anticipate that continuing capital investments and changes in operating procedures will be required for the foreseeable future to comply with existing and new requirements as well as evolving interpretations and more strict enforcement of existing laws and regulations.
Magnolia Station Crude Oil Release
On March 9, 2013, a release of crude oil was detected within a pumping facility at our Magnolia Station located west of Delek's El Dorado, Arkansas refinery (the "El Dorado Refinery"). The pumping facility is owned by our subsidiary SALA Gathering Systems, LLC. Since detecting the release we have worked to contain the release, recover the released crude oil and remediate those areas impacted by the release, coordinating our efforts with the EPA and state authorities to restore the impacted area to the satisfaction of the appropriate regulatory authorities. As of the date of this filing, we believe we have substantially completed all necessary remediation, restoration and monitoring of the areas affected by the crude oil release, although there are on-going discussions with ADEQ regarding whether additional monitoring or remediation of soil may be necessary. The release did not impact the delivery of crude oil from the Magnolia Station to the El Dorado Refinery and did not interrupt the operations of the El Dorado Pipeline connected to the Magnolia Station.
We believe the total costs and liabilities associated with this event are immaterial to our operations and financial results as Delek is required, pursuant to the terms of the Omnibus Agreement (as described in
Note 18
—Related Party Transactions) to pay to us any costs in excess of
$0.25 million
with respect to this event that we incurred as a result of the failure at the pumping facility and resulting release.
Macedonia Crude Oil Release
On October 7, 2013, a release of crude oil was identified from a gathering line near Macedonia, Arkansas. Approximately 40 barrels of crude oil were recovered from an adjacent small creek. Other than maintaining booms on a portion of the creek, cleanup operations for the creek were essentially concluded in November 2013; however, remediation of impacted soils along the pipeline remains to be completed. Based on current information available to us, we do not believe the total costs associated with this event, including any fines or penalties and net of partial insurance reimbursement, will have a material adverse effect upon our business, financial condition or results of operations.
Contracts and Agreements
Substantially all of the petroleum products we sell in west Texas are purchased from two suppliers, Noble Petro, Inc. ("Noble Petro") and on Asset Services, L.P. ("Magellan"). Under the terms of a supply contract (the "Abilene Contract") with Noble Petro, we are able to purchase up to
20,350
bpd of petroleum products at the Abilene, Texas terminal, which we own, for sales at the Abilene and San Angelo terminals and to exchange barrels with third parties. We lease the Abilene and San Angelo, Texas terminals to Noble Petro, under a separate Terminal and Pipeline Lease and Operating Agreement, with a term that runs concurrent with that of the Abilene Contract. The Abilene Contract expires on
December 31, 2017
. There are no options to renew the contract.
Under the terms of our contract with Magellan (the "East Houston contract"), we had in 2013 the right to purchase up to
7,000
bpd of refined products for resale at third-party terminals located in Aledo, Odessa and Frost, Texas along the Magellan Orion Pipeline. We owned the inventory purchased under the East Houston contract. To hedge our exposure to fluctuations in commodity prices for the period between our purchase of products from Magellan and subsequent sales to our customers, from time to time we entered into Gulf Coast product swap arrangements with respect to the products we purchased. The East Houston contract was terminated in January 2014. We are currently discussing the possibility of a new contract with Magellan and are purchasing spot barrels on similar terms from third parties for sale to wholesale customers.
F-32
Letters of Credit
As of
December 31, 2013
, we had in place letters of credit totaling
$12.0 million
under the Amended and Restated Credit Agreement primarily securing obligations with respect to gasoline and diesel purchases. No amounts were drawn by beneficiaries of these letters of credit at
December 31, 2013
.
Operating Leases
We lease certain equipment and have surface leases under various operating lease arrangements, most of which provide the option, after the initial lease term, to renew the leases. None of these lease arrangements include fixed rental rate increases. Lease expense for all operating leases for the years ended
December 31, 2013
,
2012
and
2011
totaled
$0.5 million
,
$0.5 million
, and
$0.3 million
, respectively.
We have a five-year ground lease agreement with Lion Oil effective November 7, 2012 for the land on which an above ground storage tank and related facilities are located. The land measures approximately seven acres of Lion Oil's refinery site. The tank and related facilities are used for the storage and throughput of such crude oil or other hydrocarbon substances or any resulting refined products. The fees paid to Lion Oil were insignificant for
2013
.
In connection with the Tyler Acquisition, we and Delek entered into a lease and access agreement with respect to the real property at the Tyler Terminal and Tank Assets. Under this agreement, we will lease from Delek the real property on which the Tyler Terminal and Tank Assets are located for
$100
annually, paid in advance, with an initial term of
50
years with automatic renewal for a maximum of four successive 10-year periods thereafter.
18
. Related Party Transactions
Commercial Agreements
The Partnership has various long-term, fee-based commercial agreements with Delek under which we provide crude oil gathering, crude oil and refined products transportation and storage services and marketing and terminalling services to Delek. Each of these agreements include minimum quarterly volume or throughput commitments and have tariffs or fees indexed to inflation, provided that the tariffs or fees will not be decreased below the initial amount. Fees under each agreement are payable to us monthly by Delek or certain third parties to whom Delek has assigned certain of its rights. In most circumstances, if Delek or the applicable third party assignee fails to meet or exceed the minimum volume or throughput commitment during any calendar quarter, Delek, and not any third party assignee, will be required to make a quarterly shortfall payment to us equal to the volume of the shortfall multiplied by the applicable fee. Carry-over of any volumes in excess of such commitment to any subsequent quarter is not permitted. Exceptions to this requirement that Delek make minimum payments under a given agreement can exist if (i) there is an event of force majeure affecting our asset, or (ii) after the first three years of the applicable commercial agreement's term (a) there is an event of force majeure affecting the applicable Delek asset, or (b) if Delek shuts down the applicable refinery upon giving 12 months' notice, which such notice may only be given after the first two years of the applicable commercial agreement's term. In addition, Delek may terminate any of these agreements under certain circumstances.
Under each of these agreements, we are required to maintain the capabilities of our pipelines and terminals such that Delek may throughput and/or store, as the case may be, specified volumes of crude oil and refined products. To the extent that Delek is prevented by our failure to maintain such capacities from throughputting or storing such specified volumes for more than 30 days per year, Delek's minimum throughput commitment will be reduced proportionately and prorated for the portion of the quarter during which the specified throughput capacity was unavailable, and/or the storage fee will be reduced, prorated for the portion of the month during which the specified storage capacity was unavailable. Such reduction would occur even if actual throughput or storage amounts were below the minimum volume commitment levels.
The tariffs, throughput fees and the storage fees under our agreements with Delek are subject to increase or decrease on July 1 of each year, by the amount of any change in the FERC oil pipeline index or, in the case of the east Texas marketing agreement, to the consumer price index; provided, however, that in no event will the fees be adjusted below the amount initially set forth in the applicable agreement.
We believe the terms and conditions under these agreements, as well as our other agreements with Delek described below, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. These commercial agreements with Delek include the following:
F-33
|
Asset/Operation
|
Initiation Date
|
Initial/Maximum Term (years)
(1)
|
Service
|
Minimum Throughput Commitment (bpd)
|
Fee (/bbl)
|
||||||
|
Lion Pipeline System and SALA Gathering System:
|
|||||||||||
|
Crude Oil Pipelines (non-gathered)
|
November 2012
|
5 / 15
|
Crude oil and refined products transportation
|
46,000
(2)
|
$ 0 .89
(3)
|
|
|||||
|
Refined Products Pipelines
|
November 2012
|
40,000
|
$
|
0.105
|
|
||||||
|
SALA Gathering System
|
November 2012
|
Crude oil gathering
|
14,000
|
$ 2.35
(3)
|
|
||||||
|
East Texas Crude Logistics System:
|
|||||||||||
|
Crude Oil Pipelines
|
November 2012
|
5 / 15
|
Crude oil transportation and storage
|
35,000
|
$ 0.42
(4)
|
|
|||||
|
Storage
|
November 2012
|
N/A
|
$261,480/month
|
||||||||
|
East Texas Marketing
|
November 2012
|
10
(5)
|
Marketing products for Tyler Refinery
|
50,000
|
$ .6065/bbl
(5)
|
||||||
|
Memphis Terminal
|
November 2012
|
5 / 15
|
Dedicated terminalling services
|
10,000
|
$
|
0.52
|
|
||||
|
Big Sandy Terminal:
(6)
|
|||||||||||
|
Refined Products Transportation
|
November 2012
|
5 / 15
|
Refined products transportation, dedicated terminalling services and storage for the Tyler Refinery
|
5,000
|
$
|
0.52
|
|
||||
|
Terminalling
|
November 2012
|
5,000
|
$
|
0.52
|
|
||||||
|
Storage
|
November 2012
|
N/A
|
$52,250/month
|
||||||||
|
Tyler Throughput and Tankage:
|
|||||||||||
|
Refined Products Throughput
|
July 2013
|
8 / 16
|
Dedicated Terminalling and storage
|
50,000
|
$
|
0.35
|
|
||||
|
Storage
|
July 2013
|
N/A
|
$841,667/month
|
||||||||
|
Tyler Lease and Access
|
July 2013
|
50
|
Real property lease
|
N/A
|
$100 annually
|
||||||
|
Tyler Site Services
|
July 2013
|
8 / 16
|
Shared services
|
N/A
|
$200,000 annually
|
||||||
|
North Little Rock Terminal:
|
|||||||||||
|
Terminalling
|
October 2013
|
8 / 16
|
Dedicated terminalling and storage services
|
8,100
|
$ 0.23
(7)
|
|
|||||
|
Storage
|
October 2013
|
8 / 16
|
N/A
|
$63,000/month
(7)
|
|||||||
|
(1)
|
Maximum
term gives effect to the extension of the commercial agreement pursuant to the terms thereof.
|
F-34
|
(2)
|
Excludes volumes gathered on the SALA Gathering System
|
|
(3)
|
Volumes
gathered on the SALA Gathering System will not be subject to an additional fee for transportation on our Lion Pipeline System to the El Dorado Refinery
|
|
(4)
|
For
any volumes in excess of
50,000
bpd, the throughput fee will be
$0.638
/bbl.
|
|
(5)
|
Following
the primary term, the marketing agreement automatically renews for successive one-year terms unless either party provides notice of non-renewal 10 months prior to the expiration of the then-current term. An additional fee of 50% of the margin on products sold is also paid pursuant to the agreement. The fee shall not be less than
$175,000
nor greater than
$500,000
per quarter.
|
|
(6)
|
On
July 19, 2013, we acquired the Hopewell Pipeline in order to effectively connect it with the Big Sandy Pipeline and thereby return the Big Sandy Terminal to operation. In connection with the acquisition, on July 25, 2013, we and Delek entered into the Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline), which amended and restated the terminalling services agreement for the Big Sandy Terminal originally entered into in connection with the Offering. Even though the Big Sandy Terminal was not operational for a majority of the year ended
December 31, 2013
, as the pipeline required maintenance in order to return it to service, Delek paid to us the minimum terminal and storage fees for the Big Sandy Terminal pursuant to the agreement above. The terminal was available for use by Delek, beginning in the fourth quarter 2013.
|
|
(7)
|
Pursuant
to the agreement, capital projects are to be completed in two phases in order to support and enhance blending activities at the terminal. Upon completion of phase II capital projects, the minimum throughput fees will decrease and storage fees will increase.
|
El Dorado Refinery Crude Oil and Refined Products Supply and Offtake Arrangement
Pursuant to an arrangement with Delek and Lion Oil, to which we are not a party, J. Aron & Company ("J. Aron") acquires and holds title to substantially all crude oil and refined products transported on our Lion Pipeline System and SALA Gathering System. J. Aron is therefore considered the shipper for the liquid it owns on the Lion Pipeline System and the SALA Gathering System. J. Aron also has title to the refined products stored at our Memphis and North Little Rock terminals. Under (i) our pipelines and storage agreement with Lion Oil relating to the Lion Pipeline System and the SALA Gathering System, (ii) our terminalling agreements with Lion Oil relating to the Memphis and North Little Rock terminals and (iii) our throughput and tankage agreement relating to the El Dorado Terminal and Tank Assets, Lion Oil has assigned to J. Aron certain of its rights under these agreements, including the right to have J. Aron's crude oil and intermediate and refined products stored in or transported on or through these systems, Memphis and North Little Rock terminals and the El Dorado Terminal and Tank Assets, with Lion Oil acting as J. Aron's agent for scheduling purposes. Accordingly, even though this is effectively a financing arrangement for Delek whereby J. Aron sells the product back to Delek, J. Aron is technically our primary customer under each of these agreements. J. Aron will retain these storage and transportation rights for the term of its arrangement with Delek and Lion Oil, which currently runs through April 30, 2017, and J. Aron will pay us for the transportation, throughput and storage services we provide to it. The rights assigned to J. Aron will not alter Lion Oil's obligations to meet certain throughput minimum volumes under our agreements with respect to the transportation, throughputting and storage of crude oil and refined products through our facilities, but J. Aron's throughput will be credited toward Lion Oil's minimum throughout commitments. Accordingly, Lion Oil will be responsible for making any shortfall payments incurred under the pipelines and storage agreement or the terminalling agreement which may result from minimum throughputs or volumes not being met.
Other Agreements with Delek
In addition to the the commercial agreements described above, the Partnership has entered into the following agreements with Delek:
Omnibus Agreement
The Partnership entered into an omnibus agreement with Delek, our general partner, our subsidiary, Delek Logistics Operating, LLC ("OpCo"), Delek, Lion Oil, and certain of the Partnership’s and Delek’s other subsidiaries upon the completion of the Offering on November 7, 2012. We refer to this omnibus agreement, as subsequently amended, as the “Omnibus Agreement.”
On July 26, 2013, in connection with the acquisition from Delek of the refined products terminal and 96 storage tanks and ancillary assets adjacent to the Tyler Refinery from Delek, the Partnership entered into an amendment and restatement of the Omnibus Agreement (the “First Omnibus Amendment”). The First Omnibus Amendment, included the following, among other things: (i) certain modifications in the reimbursement by Delek and certain of its subsidiaries under the Omnibus Agreement for certain operating expenses and capital expenditures incurred by the Partnership or its subsidiaries, (ii) certain modifications
F-35
of the indemnification provisions under the Omnibus Agreement in favor of the Partnership with respect to certain environmental matters, and (iii) the increase of the annual administrative fee payable by us to Delek under the Omnibus Agreement for corporate general and administrative services.
The annual administrative fee payable by the Partnership to Delek for corporate general and administrative services that Delek and its affiliates provide under the First Omnibus Amendment, increased from
$2.7 million
to
$3.0 million
, which is prorated and payable monthly. We paid Delek approximately
$3.7 million
pursuant to the Omnibus Agreement, which includes
$2.8 million
related to general and administrative services and
$0.9 million
related to insurance coverage during the year ended
December 31, 2013
. Delek paid us approximately
$0.9 million
pursuant to the Omnibus Agreement during the year ended
December 31, 2013
as indemnification relative to the Paline Pipeline System.
Under the Omnibus Agreement, Delek has agreed to reimburse us for certain expenses that we incur for inspections, maintenance and repairs to any storage tanks we acquired in the Tyler Acquisition to cause such storage tanks to comply with applicable regulatory and/or industry standards. Delek is also required to reimburse us for certain expenses that we incur for inspections, maintenance and repairs to any of the storage tanks contributed to us by Delek (subject to a deductible of
$0.5 million
per year) that are necessary to comply with the DOT pipeline integrity rules and certain American Petroleum Institute storage tank standards for a period of five years. Furthermore, under the Omnibus Agreement, Delek was required to reimburse us for all non-discretionary maintenance capital expenditures with respect to the Tyler Terminal and Tank Assets in excess of
$0.4 million
for the period from July 26, 2013 through September 30, 2013. Delek was also required to reimburse us for non-discretionary maintenance capital expenditures with respect to all assets transferred from Delek to the Partnership in excess of
$1.4 million
for the period from September 30, 2013 through December 31, 2013.
For additional information regarding the Omnibus Agreement, see “
Note 20
—Subsequent Events—El Dorado Terminal and Tankage Acquisition”
Operation and Management Services Agreement
Our general partner operates our business on our behalf and is entitled under our partnership agreement to be reimbursed for the cost of providing those services. We and our general partner entered into an operation and management services agreement with Delek, pursuant to which our general partner uses employees of Delek to provide operation and management services with respect to our pipelines, storage and terminalling facilities and related assets, including operating and maintaining flow and pressure control, maintaining and repairing our pipelines, storage and terminalling facilities and related assets, conducting routine operational activities, and managing transportation and logistics, contract administration, crude oil and refined product measurement, database mapping, rights-of-way, materials, engineering support and such other services as our general partner and Delek may mutually agree upon from time to time. We and/or our general partner reimbursed Delek for such services under the operation and management services agreement. We and our subsidiaries paid Delek approximately
$5.9 million
pursuant to this agreement during the year ended
December 31, 2013
.
On July 26, 2013, in connection with the Tyler Acquisition, the Partnership, our general partner and Delek Logistics Services Company terminated the operation and management services agreement. We continued to reimburse our general partner for the services it provides to us under our partnership agreement. We reimbursed our general partner
$6.5 million
pursuant to the partnership agreement during the year ended
December 31, 2013
.
Other Agreements
Paline Pipeline System Capacity Reservation
. In 2011, prior to our purchase of the Paline Pipeline, a major integrated oil company contracted with the prior owner of the Paline Pipeline System to reverse the pipeline to primarily run southbound. In exchange, the oil company agreed to pay for use of 100% of such southbound capacity for a fee of
$450,000
and
$529,250
per month in 2012 and 2013, respectively. The agreement will thereafter be subject to annual escalation based on the change in the producer price index for finished goods during any renewal periods. The monthly fees payable to us under our agreement with this customer will increase proportionately to the extent throughput volumes are above
30,000
bpd. To the extent we are unable to provide our customer with 30,000 barrels of throughput capacity during a given month, the monthly fee may be reduced accordingly. The agreement extends through December 31, 2014 and will renew automatically each year unless terminated by either party at least six months prior to the year end.
Pursuant to the terms of the usage contract, this customer was required to make only payments of
$229,000
per month for this capacity until the final segment of the reversal of the Paline Pipeline System was completed, and we entered into a connection agreement with an affiliate of the customer to connect our system with such affiliate's tanks. We completed our work on the fourth segment of the reversal in October 2012. However, a connection agreement was not fully executed until April 2013. Even though our customer had not yet completed the work on its tanks, because we completed our necessary work, we believe we were owed the full payment under the contract beginning in November 2012. Our customer paid only
$229,000
per month in 2012 and during the first quarter 2013. Pursuant to the Omnibus Agreement, Delek is required to indemnify us during the period from November 1, 2012 through December 31, 2013 for any lost service fees attributable to the failure of our customer to pay 100% of the full monthly fee. Therefore, Delek indemnified us for lost service fees related to the Paline Pipeline System
F-36
in 2012 and during the first quarter 2013. Beginning in the second quarter of 2013 and for the rest of 2013, each month we received the entire monthly amount payable to us of
$529,250
.
Predecessors' Transactions
Related-party transactions of the Predecessors were settled through division equity. Revenues from affiliates consist of revenues from gathering, pipeline transportation, storage, wholesale marketing and products terminalling services to Delek and its affiliates based on regulated tariff rates or contractually based fees.
Costs related specifically to us have been identified and included in the accompanying consolidated statements of income and comprehensive income. Prior to the Offering and the Tyler Acquisition, we were not allocated certain corporate costs. These costs were primarily allocated based on a percentage of salaries expense and property, plant and equipment costs. In the opinion of management, the methods for allocating these costs are reasonable. It is not practicable to estimate the costs that would have been incurred by us if we had been operated on a stand-alone basis.
Summary of Transactions
A summary of revenue and expense transactions with Delek, including expenses directly charged and allocated to our Predecessors, are as follows (in thousands):
|
Year Ended December 31,
|
||||||||||||
|
2013
|
2012
|
2011
|
||||||||||
|
Predecessors
|
Predecessors
|
|||||||||||
|
Revenues
|
$
|
77,272
|
|
$
|
43,216
|
|
$
|
34,266
|
|
|||
|
Operating and maintenance expenses
(1)
|
$
|
14,718
|
|
$
|
3,394
|
|
$
|
3,291
|
|
|||
|
General and administrative expenses
(2)
|
$
|
3,341
|
|
$
|
4,944
|
|
$
|
3,125
|
|
|||
|
(1)
|
Operating
and maintenance expenses include costs allocated to the Tyler Predecessor for operating support provided to the Tyler Predecessor by Delek Refining, including certain labor related costs, property and liability insurance costs and certain other operating expenses. The costs that were allocated to us were
$1.4 million
for the year ended
December 31, 2013
, and
$2.7 million
, for each of the years ended
December 31, 2012
and
2011
.
|
|
(2)
|
General and administrative expenses include costs allocated to the Tyler Predecessor for general and administrative support provided to the Tyler Predecessor by Delek Refining, including services such as corporate management, risk management, accounting and human resources. The costs that were allocated to us were
$0.5 million
,
$0.8 million
and
$0.7 million
for the years ended
December 31, 2013
,
2012
and
2011
, respectively.
|
Quarterly Cash Distribution
In accordance with our partnership agreement, our common, subordinated and general partner unitholders are entitled to receive quarterly distributions of available cash. On
January 23, 2014
, we declared a quarterly cash distribution of
$0.415
per unit based on the results of the fourth quarter of
2013
, which was paid on
February 13, 2014
.
19
. Selected Quarterly Financial Data (Unaudited)
Quarterly financial information for the years ended
December 31, 2013
and
2012
is summarized below. The quarterly financial information summarized below has been prepared by management and is unaudited (in thousands, except per unit data). On July 26, 2013, we acquired the Tyler Terminal and Tank Assets from Delek. Our and our Predecessors' historical data has been retrospectively adjusted to reflect the results of operations attributable to the Tyler Terminal and Tank Assets as if we owned the assets for all periods presented.
F-37
|
For the Three Month Periods Ended
|
||||||||||||||||
|
March 31, 2013
|
June 30, 2013
|
September 30, 2013
|
December 31, 2013
|
|||||||||||||
|
Net sales
|
$
|
210,894
|
|
$
|
230,141
|
|
$
|
243,295
|
|
$
|
223,097
|
|
||||
|
Operating income
|
$
|
10,309
|
|
$
|
9,766
|
|
$
|
12,887
|
|
$
|
13,342
|
|
||||
|
Net income
|
$
|
9,370
|
|
$
|
8,896
|
|
$
|
11,386
|
|
$
|
11,325
|
|
||||
|
Limited partners' interest in net income
|
$
|
11,960
|
|
$
|
11,521
|
|
$
|
12,295
|
|
11,098
|
|
|||||
|
Net income per limited partner unit:
|
|
|
||||||||||||||
|
Common (basic)
|
$
|
0.50
|
|
$
|
0.48
|
|
$
|
0.51
|
|
$
|
0.46
|
|
||||
|
Common (diluted)
|
$
|
0.50
|
|
$
|
0.47
|
|
$
|
0.51
|
|
$
|
0.46
|
|
||||
|
Subordinated - Delek (basic and diluted)
|
$
|
0.50
|
|
$
|
0.48
|
|
$
|
0.51
|
|
$
|
0.46
|
|
||||
|
For the Three Month Periods Ended
|
||||||||||||||||
|
March 31, 2012
(1)
|
June 30, 2012
(1)
|
September 30, 2012
(1)
|
December 31, 2012
(1)
|
|||||||||||||
|
Net sales
|
$
|
239,084
|
|
$
|
262,480
|
|
$
|
271,806
|
|
$
|
249,216
|
|
||||
|
Operating income
|
$
|
3,730
|
|
$
|
2,031
|
|
$
|
2,560
|
|
$
|
5,155
|
|
||||
|
Net income (loss)
(3)
|
$
|
1,322
|
|
$
|
584
|
|
$
|
(544
|
)
|
$
|
23,456
|
|
||||
|
Limited partners' interest in net income
|
|
|
|
$
|
8,242
|
|
||||||||||
|
Net income per limited partner unit:
(2)
|
||||||||||||||||
|
Common (basic)
|
|
|
|
|
$
|
0.34
|
|
|||||||||
|
Common (diluted)
|
$
|
0.34
|
|
|||||||||||||
|
Subordinated - Delek (basic and diluted)
|
|
|
|
|
$
|
0.34
|
|
|||||||||
|
(1)
|
The
information presented includes the results of operations of the DKL Predecessor for periods presented through November 6, 2012 and of the Tyler Predecessor for all periods presented, and of the Partnership for the period beginning November 7, 2012, the date the Partnership commenced operations.
|
|
(2)
|
Net income per unit is only calculated for the Partnership after the Offering as no units were outstanding prior to November 7, 2012.
|
|
(3)
|
Net income for the year ended December 31, 2012 includes a one-time tax benefit of
$18.5 million
. The majority of the Partnership's deferred tax assets and liabilities relates to the Predecessor's conversion from a corporation to a partnership and as a result of such conversion we are not subject to federal income taxes. The conversion from a taxable corporation to a passthrough resulted in this one-time tax benefit.
|
20
. Subsequent Events
Distribution Declaration
On
January 23, 2014
, our general partner's board of directors declared a quarterly cash distribution of
$0.415
per share, paid on
February 13, 2014
, to unitholders of record on
February 4, 2014
.
El Dorado Terminal and Tankage Acquisition
On
February 10, 2014
, the Partnership, through OpCo, completed a transaction with Lion Oil, pursuant to which OpCo acquired a refined products terminal, storage tanks and ancillary assets adjacent to the El Dorado Refinery from Lion Oil (the "El Dorado Transaction"). We acquired the El Dorado assets, defined below, to complement our existing assets and provide attractive returns for our unitholders. The purchase price paid for the assets acquired was
$95.9 million
in cash financed with borrowings under the Partnership's amended and restated senior secured revolving credit facility. As the initial accounting for the El Dorado Transaction was incomplete at the time the financial statements were available to be issued, there are no pro forma disclosures available for the year ended
December 31, 2013
.
F-38
The assets acquired in the El Dorado Transaction consist of:
|
•
|
The refined products terminal located at the El Dorado Refinery (the "El Dorado Terminal"), which consists of a truck loading rack with three loading bays supplied by pipeline from storage tanks located at the El Dorado Refinery, along with certain ancillary assets. Total throughput capacity for the El Dorado Terminal is approximately
26,700
bpd. For the year ended December 31, 2012, approximately
12,649
bpd of refined products were throughput at the El Dorado Terminal.
|
|
•
|
158
storage tanks and certain ancillary assets (such as pumps and piping) located adjacent to the El Dorado Refinery with an aggregate shell capacity of approximately
2.5
million barrels (such storage tanks and certain ancillary assets, the "El Dorado Storage Tanks"). The El Dorado Storage Tanks, together with the El Dorado Terminal, are sometimes hereinafter referred to as the "El Dorado Assets."
|
In connection with the El Dorado Transaction, the Partnership entered into and amended, as applicable, the following definitive agreements:
El Dorado Throughput and Tankage Agreement.
On
February 10, 2014
, in connection with the El Dorado Transaction, Lion Oil and OpCo, and, for limited purposes, J. Aron, entered into the El Dorado Throughput and Tankage Agreement. Under the El Dorado Throughput and Tankage Agreement, OpCo will provide Lion Oil with throughput and storage services in return for throughput and storage fees. The initial term of the El Dorado Throughput and Tankage Agreement is
eight
years and Lion Oil, at its sole option, may extend the term for two renewal terms of four years each.
Second Omnibus Amendment.
On
February 10, 2014
, in connection with the El Dorado Transaction, the Partnership entered into a second amendment and restatement of Omnibus Agreement with our general partner, OpCo, certain of the Partnership's other subsidiaries, Delek, Lion Oil and Delek Refining (the "Second Omnibus Amendment"). The Second Omnibus Amendment included, among other things: (i) certain modifications in the reimbursement by Delek US and certain of its subsidiaries under the Omnibus Agreement for certain operating expenses and capital expenditures incurred by the Partnership or its subsidiaries; (ii) certain modifications of the indemnification provisions under the Omnibus Agreement in favor of the Partnership with respect to certain environmental matters; and (iii) the increase of the annual administrative fee payable by us to Delek under the Omnibus Agreement for corporate general and administrative services from
$3.0
million to
$3.3
million, which is prorated and payable monthly.
El Dorado Lease and Access Agreement.
On
February 10, 2014
, in connection with the El Dorado Transaction, Lion Oil and OpCo entered into the El Dorado Lease and Access Agreement (the "El Dorado Lease"). Under the El Dorado Lease, OpCo will lease from Lion Oil the real property on which the El Dorado Assets are located. The El Dorado Lease has an initial term of
50
years with automatic renewal for a maximum of four successive 10-year periods thereafter.
El Dorado Site Services Agreement.
On
February 10, 2014
, in connection with the El Dorado Transaction, Lion Oil and OpCo entered into the El Dorado Site Services Agreement. Under the El Dorado Site Services Agreement, Lion Oil will provide OpCo with shared use of certain services, materials and facilities that are necessary to operate and maintain the El Dorado Assets as currently operated and maintained. The term of the El Dorado Site Services Agreement is co-terminous with the El Dorado Lease discussed above.
F-39
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.
Delek Logistics Partners, LP
by and through its general partner, Delek Logistics GP, LLC
By:
/s/ Assaf Ginzburg
Assaf Ginzburg
Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
Dated:
March 4, 2014
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by or on behalf of the following persons on behalf of the registrant and in the capacities indicated on
March 4, 2014
:
/
s/ Ezra Uzi Yemin
Ezra Uzi Yemin
Chairman of the Board of Directors and Chief
Executive Officer
(Principal Executive Officer)
/
s/ Assaf Ginzburg
Assaf Ginzburg
Director, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
/
s/ Frederec Green
Frederec Green
Director
/s/ Charles J. Brown, III*
Charles J. Brown, III
Director
/
s/ Eric D. Gadd*
Eric D. Gadd
Director
/
s/ Gary M. Sullivan, Jr.*
Gary M. Sullivan, Jr.
Director
/
s/ Mark B. Cox*
Mark B. Cox
Director
*By:
/s/ Assaf Ginzburg
Assaf Ginzburg
Individually and as Attorney-in-Fact
F-40
EXHIBIT INDEX
|
Exhibit No.
|
Description
|
||
|
3.1
|
Certificate of Limited Partnership of Delek Logistics Partners, LP (incorporated by reference to Exhibit 3.1 to the Partnership's Form S-1 (File No. 333-182631) filed on July 12, 2012).
|
||
|
3.2
|
First Amended and Restated Agreement of Limited Partnership of Delek Logistics Partners, LP, dated November 7, 2012 (incorporated by reference to Exhibit 3.1 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
3.3
|
Certificate of Formation of Delek Logistics GP, LLC (incorporated by reference to Exhibit 3.3 to the Partnership's Registration Statement on Form S-1 (File No. 333-182631) filed on July 12, 2012).
|
||
|
3.4
|
Third Amended and Restated Limited Liability Company Agreement of Delek Logistics GP, LLC, dated as of December 10, 2013 (incorporated by reference to Exhibit 3.1 to the Partnership’s Form 8-K filed on December 13, 2013).
|
||
|
10.1
|
Second Amended and Restated Omnibus Agreement, dated as of February 10, 2014, by and among Delek US Holdings, Inc., Lion Oil Company, Delek Logistics Operating, LLC, Delek Marketing & Supply, LP, Delek Refining, Ltd., Delek Logistics Partners, LP, Paline Pipeline Company, LLC, SALA Gathering Systems, LLC, Magnolia Pipeline Company, LLC, El Dorado Pipeline Company, LLC, Delek Crude Logistics, LLC, Delek Marketing-Big Sandy, LLC and Delek Logistics GP, LLC (incorporated by reference to Exhibit 10.2 to the Partnership’s Form 8-K filed on February 14, 2014).
|
||
|
10.2
|
Operation and Management Services Agreement, dated November 7, 2012, by and among Delek Logistics Services Company, Delek Logistics Partners, LP and Delek Logistics GP, LLC.
(incorporated by reference to Exhibit 10.2 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.3
|
Amended and Restated Credit Agreement, dated July 9, 2013, by and among Delek Logistics Partners, LP, Delek Logistics Operating, LLC, Delek Marketing GP, LLC, Delek Marketing & Supply, LP, Delek Crude Logistics, LLC, Delek Marketing-Big Sandy, LLC, Magnolia Pipeline Company, LLC, El Dorado Pipeline Company, LLC, SALA Gathering Systems, LLC, and Paline Pipeline Company, LLC and Fifth Third Bank, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on July 12, 2013).
|
||
|
10.4
|
Contribution, Conveyance and Assumption Agreement, dated November 7, 2012, by and among Delek Logistics Partners, LP, Delek Logistics GP, LLC, Delek Logistics Operating, LLC, Delek Crude Logistics, LLC, Delek US Holdings, Inc., Delek Marketing & Supply, LLC, Delek Marketing and Supply, LP, Lion Oil Company and Delek Logistics Services Company (incorporated by reference to Exhibit 10.4 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.5
|
*
|
Delek Logistics GP, LLC 2012 Long-Term Incentive Plan, dated November 7, 2012 (incorporated by reference to Exhibit 10.5 to the Partnership's Form 8-K filed on November 7, 2012).
|
|
|
10.6
|
++
|
Marketing Agreement, dated November 7, 2012, by and between Delek Refining, Ltd. and Delek Marketing & Supply, LP (incorporated by reference to Exhibit 10.6 to the Partnership's Form 8-K filed on November 7, 2012).
|
|
|
10.7
|
Pipelines and Tankage Agreement (East Texas Crude Logistics System), dated November 7, 2012, by and between Delek Refining, Ltd. and Delek Crude Logistics, LLC (incorporated by reference to Exhibit 10.7 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.8
|
Terminalling Services Agreement (Big Sandy Terminal), dated November 7, 2012, by and between Delek Refining, Ltd. and Delek Marketing-Big Sandy, LLC (incorporated by reference to Exhibit 10.8 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.9
|
Amended and Restated Services Agreement (Big Sandy Terminal and Pipeline), dated July 25, 2013, by and between Delek Refining, Ltd. and Delek Marketing-Big Sandy, LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K/A filed on July 31, 2013).
|
||
F-41
|
10.10
|
Pipelines and Storage Facilities Agreement, dated November 7, 2012, by and among Lion Oil Company, Delek Logistics Partners, LP, SALA Gathering Systems, LLC, El Dorado Pipeline Company, LLC, Magnolia Pipeline Company, LLC and J. Aron & Company (incorporated by reference to Exhibit 10.9 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.11
|
Terminalling Services Agreement (Memphis Terminal), dated November 7, 2012, by and between Lion Oil Company, Delek Logistics Operating, LLC and J. Aron & Company (incorporated by reference to Exhibit 10.10 to the Partnership's Form 8-K filed on November 7, 2012).
|
||
|
10.12
|
*
|
Form of Director Phantom Unit Award (incorporated by reference to Exhibit 10.6 to the Partnership's Amendment No. 3 to Registration Statement on Form S-1 (File No. 333-182631), filed on October 16, 2012).
|
|
|
10.13
|
*
|
Form of Employee Phantom Unit Award (incorporated by reference to Exhibit 10.7 to the Partnership's Amendment No. 3 to Registration Statement on Form S-1 (File No. 333-182631), filed on October 16, 2012).
|
|
|
10.14
|
*
|
Form of Indemnification Agreement for Directors and Officers of Delek Logistics GP, LLC (incorporated by reference to Exhibit 10.13 to the Partnership's Amendment No. 4 to Registration Statement on Form S-1 (File No. 333-182631), filed on October 24, 2012).
|
|
|
10.15
|
Asset Purchase Agreement, dated July 26, 2013, by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on August 1, 2013).
|
||
|
10.16
|
Tyler Throughput and Tankage Agreement, dated July 26, 2013 by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.3 to the Partnership’s Form 8-K filed on August 1, 2013).
|
||
|
10.17
|
Tyler Lease and Access Agreement, dated July 26, 2013, by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.4 to the Partnership’s Form 8-K filed on August 1, 2013).
|
||
|
10.18
|
Tyler Site Services Agreement, dated July 26, 2013, by and between Delek Marketing & Supply, LP and Delek Refining, Ltd. (incorporated by reference to Exhibit 10.5 to the Partnership’s Form 8-K filed on August 1, 2013).
|
||
|
10.19
|
Asset Purchase Agreement, dated as of February 10, 2014, between Lion Oil Company and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on February 14, 2014).
|
||
|
10.20
|
El Dorado Throughput and Tankage Agreement, dated as of February 10, 2014, between Lion Oil Company and Delek Logistics Operating, LLC, and for limited purposes, J. Aron & Company (incorporated by reference to Exhibit 10.3 to the Partnership’s Form 8-K filed on February 14, 2014).
|
||
|
10.21
|
El Dorado Lease and Access Agreement, dated as of February 10, 2014, between Lion Oil Company and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.4 to the Partnership’s Form 8-K filed on February 14, 2014).
|
||
|
10.22
|
El Dorado Site Services Agreement, dated as of February 10, 2014, between Lion Oil Company and Delek Logistics Operating, LLC (incorporated by reference to Exhibit 10.5 to the Partnership’s Form 8-K filed on February 14, 2014).
|
||
|
21.1
|
#
|
Subsidiaries of Registrant.
|
|
|
23.1
|
#
|
Consent of Independent Registered Public Accounting Firm (Ernst & Young LLP).
|
|
|
24.1
|
#
|
Power of Attorney.
|
|
|
31.1
|
#
|
Certification of Delek Logistics GP, LLC's Chief Executive Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act of 1934, as amended.
|
|
|
31.2
|
#
|
Certification of Delek Logistics GP, LLC's Chief Financial Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act of 1934, as amended.
|
|
|
32.1
|
#
|
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
32.2
|
#
|
Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
F-42
|
101
|
^
|
The following materials from Delek Logistics Partners, LP Annual Report on Form 10-K for the annual period ended December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of December 31, 2013 and 2012; (ii) Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2013, 2012 and 2011; (iii) Consolidated Statements of Changes in Partners’ Equity for the years ended December 31, 2013, 2012 and 2011; (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; and (v) Notes to Consolidated Financial Statements.
|
|
|
*
|
Management contract or compensatory plan or arrangement.
|
||
|
#
|
Filed herewith.
|
||
|
++
|
Confidential treatment has been requested and granted with respect to certain portions of this exhibit pursuant to Rule 24b-2 of the Securities Exchange Act of 1934. Omitted portions have been filed separately with the Securities and Exchange Commission.
|
||
|
^
|
Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files in Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.
|
||
F-43
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. Mine Safety DisclosuresPart IIItem 5. Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions and Director IndependenceItem 14. Principal Accountant Fees and ServicesPart IVItem 15. Exhibits and Financial Statement Schedules