FORM 10-Q
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2010
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT OF 1934
For the transition period from                      to                     .
Commission File Number: 1-32225
HOLLY ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
     
Delaware   20-0833098
     
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification No.)
100 Crescent Court, Suite 1600
Dallas, Texas 75201-6915
(Address of principal executive offices)
(214) 871-3555
(Registrant’s telephone number, including area code)
None
(Former name, former address and former fiscal year, if changed since last report)
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 þ No o
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 (§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 o No o
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.
             
Large accelerated filer o   Accelerated filer þ   Non-accelerated filer o   Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No þ
The number of the registrant’s outstanding common units at July 23, 2010 was 22,078,509.
 
 

 

 


 

HOLLY ENERGY PARTNERS, L.P.
INDEX
         
    3  
 
       
    3  
 
       
    4  
 
       
    4  
 
       
    5  
 
       
    6  
 
       
    7  
 
       
    8  
 
       
    26  
 
       
    44  
 
       
    44  
 
       
    45  
 
       
    45  
 
       
    45  
 
       
    46  
 
       
 Exhibit 4.1
 Exhibit 4.2
 Exhibit 4.3
 Exhibit 4.4
 Exhibit 10.1
 Exhibit 10.2
 Exhibit 12.1
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2

 

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PART I. FINANCIAL INFORMATION
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-Q, including, but not limited to, those under “Results of Operations” and “Liquidity and Capital Resources” in Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I are forward-looking statements. Forward looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations. These statements are based on our beliefs and assumptions and those of our general partner using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurance that our expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:
   
risks and uncertainties with respect to the actual quantities of petroleum products and crude oil shipped on our pipelines and/or terminalled in our terminals;
   
the economic viability of Holly Corporation, Alon USA, Inc. and our other customers;
   
the demand for refined petroleum products in markets we serve;
   
our ability to successfully purchase and integrate additional operations in the future;
   
our ability to complete previously announced or contemplated acquisitions;
   
the availability and cost of additional debt and equity financing;
   
the possibility of reductions in production or shutdowns at refineries utilizing our pipeline and terminal facilities;
   
the effects of current and future government regulations and policies;
   
our operational efficiency in carrying out routine operations and capital construction projects;
   
the possibility of terrorist attacks and the consequences of any such attacks;
   
general economic conditions; and
   
other financial, operations and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.
Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-Q, including without limitation, the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2009 in “Risk Factors” and in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

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Item 1. Financial Statements
Holly Energy Partners, L.P.
Consolidated Balance Sheets
                 
    June 30, 2010     December 31,  
    (Unaudited)     2009  
    (In thousands, except unit data)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 2,806     $ 2,508  
Accounts receivable:
               
Trade
    6,389       4,693  
Affiliates
    16,699       14,074  
 
           
 
    23,088       18,767  
 
               
Prepaid and other current assets
    939       739  
Current assets of discontinued operations
          2,195  
 
           
Total current assets
    26,833       24,209  
 
               
Properties and equipment, net
    430,250       398,044  
Transportation agreements, net
    111,963       115,436  
Goodwill
    49,109       49,109  
Investment in SLC Pipeline
    25,819       25,919  
Other assets
    1,842       4,128  
 
           
 
               
Total assets
  $ 645,816     $ 616,845  
 
           
 
               
LIABILITIES AND PARTNERS’ EQUITY
               
Current liabilities:
               
Accounts payable:
               
Trade
  $ 3,488     $ 3,860  
Affiliates
    2,852       2,351  
 
           
 
    6,340       6,211  
 
               
Accrued interest
    7,688       2,863  
Deferred revenue
    10,923       8,402  
Accrued property taxes
    990       1,072  
Other current liabilities
    601       1,257  
 
           
Total current liabilities
    26,542       19,805  
 
               
Long-term debt
    487,479       390,827  
Other long-term liabilities
    11,984       12,349  
 
               
Partners’ equity:
               
Common unitholders (22,078,509 units and 21,141,009 units issued and outstanding at June 30, 2010 and December 31, 2009, respectively)
    274,564       275,553  
Class B subordinated unitholders (937,500 units issued and outstanding at December 31, 2009)
          21,426  
General partner interest (2% interest)
    (143,631 )     (93,974 )
Accumulated other comprehensive loss
    (11,122 )     (9,141 )
 
           
Total partners’ equity
    119,811       193,864  
 
           
 
               
Total liabilities and partners’ equity
  $ 645,816     $ 616,845  
 
           
See accompanying notes.

 

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Holly Energy Partners, L.P.
Consolidated Statements of Income
(Unaudited)
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2010     2009     2010     2009  
    (In thousands, except per unit data)  
Revenues:
                               
Affiliates
  $ 37,079     $ 25,064     $ 70,676     $ 43,387  
Third parties
    8,404       12,935       15,503       23,944  
 
                       
 
    45,483       37,999       86,179       67,331  
 
                       
 
                               
Operating costs and expenses:
                               
Operations
    13,495       10,631       26,555       20,973  
Depreciation and amortization
    7,591       6,613       14,801       12,629  
General and administrative
    1,913       1,797       4,476       3,131  
 
                       
 
    22,999       19,041       45,832       36,733  
 
                       
 
                               
Operating income
    22,484       18,958       40,347       30,598  
 
                               
Other income (expense):
                               
Equity in earnings of SLC Pipeline
    544       423       1,025       598  
SLC Pipeline acquisition costs
                      (2,500 )
Interest income
    2       2       5       8  
Interest expense
    (9,549 )     (4,404 )     (17,093 )     (9,807 )
Other
          65       (7 )     65  
 
                       
 
    (9,003 )     (3,914 )     (16,070 )     (11,636 )
 
                       
 
                               
Income from continuing operations before income taxes
    13,481       15,044       24,277       18,962  
 
                               
State income tax
    (46 )     (93 )     (140 )     (166 )
 
                       
 
                               
Income from continuing operations
    13,435       14,951       24,137       18,796  
 
                               
Income from discontinued operations, net of noncontrolling interest of $427 and $922, respectively
          1,441             3,035  
 
                       
 
                               
Net income
    13,435       16,392       24,137       21,831  
 
                               
Less general partner interest in net income, Including incentive distributions
    2,909       1,849       5,555       3,142  
 
                       
 
                               
Limited partners’ interest in net income
  $ 10,526     $ 14,543     $ 18,582     $ 18,689  
 
                       
 
                               
Limited partners’ per unit interest in earnings — basic and diluted:
                               
Income from continuing operations
  $ 0.48     $ 0.74     $ 0.84     $ 0.92  
Income from discontinued operations
          0.08             0.18  
 
                       
Net income
  $ 0.48     $ 0.82     $ 0.84     $ 1.10  
 
                       
 
                               
Weighted average limited partners’ units outstanding
    22,079       17,789       22,079       17,058  
 
                       
See accompanying notes.

 

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Holly Energy Partners, L.P.
Consolidated Statements of Cash Flows
(Unaudited)
                 
    Six Months Ended  
    June 30,  
    2010     2009(1)  
    (In thousands)  
Cash flows from operating activities
               
Net income
  $ 24,137     $ 21,831  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization
    14,801       13,109  
Equity in earnings of SLC Pipeline, net of distributions
    100       (598 )
Change in fair value — interest rate swaps
    1,464       (628 )
Noncontrolling interest in earnings of Rio Grande Pipeline Company
          922  
Amortization of restricted and performance units
    1,339       417  
(Increase) decrease in current assets:
               
Accounts receivable — trade
    (1,696 )     278  
Accounts receivable — affiliates
    (2,625 )     719  
Prepaid and other current assets
    (200 )     (234 )
Current assets of discontinued operations
    2,195        
Increase (decrease) in current liabilities:
               
Accounts payable — trade
    (372 )     1,258  
Accounts payable — affiliates
    501       (156 )
Accrued interest
    4,825       26  
Deferred revenue
    2,521       (4,669 )
Accrued property taxes
    (82 )     (119 )
Other current liabilities
    (656 )     (447 )
Other, net
    (1,066 )     541  
 
           
Net cash provided by operating activities
    45,186       32,250  
 
               
Cash flows from investing activities
               
Additions to properties and equipment
    (4,487 )     (21,826 )
Acquisition of assets from Holly Corporation
    (39,040 )     (34,200 )
Investment in SLC Pipeline
          (25,500 )
 
           
Net cash used for investing activities
    (43,527 )     (81,526 )
 
               
Cash flows from financing activities
               
Borrowings under credit agreement
    39,000       99,000  
Repayments of credit agreement borrowings
    (90,000 )     (81,000 )
Proceeds from issuance of senior notes
    147,540        
Proceeds from issuance of common units
          58,355  
Contribution from general partner
          1,191  
Distributions to HEP unitholders
    (41,312 )     (27,968 )
Distributions to noncontrolling interest
          (600 )
Purchase price in excess of transferred basis in assets acquired from Holly Corporation
    (53,960 )      
Purchase of units for restricted grants
    (2,276 )     (616 )
Deferred financing costs
    (353 )      
Cost of issuing common units
          (160 )
 
           
Net cash provided by (used for) financing activities
    (1,361 )     48,202  
 
               
Cash and cash equivalents
               
Increase (decrease) for the period
    298       (1,074 )
Beginning of period
    2,508       5,269  
 
           
 
               
End of period
  $ 2,806     $ 4,195  
 
           
     
(1)  
Includes cash flows attributable to discontinued operations.
See accompanying notes.

 

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Holly Energy Partners, L.P.
Consolidated Statement of Partners’ Equity
(Unaudited)
                                         
                            Accumulated          
            Class B     General     Other          
    Common     Subordinated     Partner     Comprehensive          
    Units     Units     Interest     Loss     Total  
    (In thousands)  
 
                                       
Balance December 31, 2009
  $ 275,553     $ 21,426     $ (93,974 )   $ (9,141 )   $ 193,864  
 
                                       
Conversion of Class B subordinated units to common units
    20,588       (20,588 )                  
Distributions to partners
    (38,966 )     (1,519 )     (827 )           (41,312 )
Purchase price in excess of transferred basis in assets acquired from Holly Corporation
                (53,960 )           (53,960 )
Purchase of units for restricted grants
    (2,276 )                       (2,276 )
Amortization of restricted and performance units
    1,339                         1,339  
Comprehensive income:
                                       
Net income
    18,326       681       5,130             24,137  
Other comprehensive loss
                      (1,981 )     (1,981 )
 
                             
Comprehensive income
    18,326       681       5,130       (1,981 )     22,156  
 
                             
 
                                       
Balance June 30, 2010
  $ 274,564     $     $ (143,631 )   $ (11,122 )   $ 119,811  
 
                             
See accompanying notes.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1: Description of Business and Presentation of Financial Statements
Holly Energy Partners, L.P. (“HEP”) together with its consolidated subsidiaries, is a publicly held master limited partnership, currently 34% owned (including the 2% general partner interest) by Holly Corporation and its subsidiaries (collectively, “Holly”). We commenced operations on July 13, 2004 upon the completion of our initial public offering. In these consolidated financial statements, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.
We operate in one business segment — the operation of petroleum product and crude oil pipelines and terminals, tankage and loading rack facilities.
We own and operate petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities that support Holly’s refining and marketing operations in west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. We also own and operate refined product pipelines and terminals, located primarily in Texas, that service Alon USA, Inc.’s (“Alon”) refinery in Big Spring, Texas. Additionally, we own a 25% joint venture interest in a 95-mile intrastate crude oil pipeline system (the “SLC Pipeline”) that serves refineries in the Salt Lake City area.
We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at our storage tanks and terminals. We do not take ownership of products that we transport, terminal or store, and therefore, we are not directly exposed to changes in commodity prices.
The consolidated financial statements included herein have been prepared without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Although certain notes and other information required by accounting principles generally accepted in the United States of America have been condensed or omitted, we believe that the disclosures in these consolidated financial statements are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with our Form 10-K for the year ended December 31, 2009. Results of operations for interim periods are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2010.
Note 2: Discontinued Operations
On December 1, 2009, we sold our 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million. Accordingly, results of operations of Rio Grande are presented in discontinued operations.
In accounting for the sale, we recorded a gain of $14.5 million and a receivable of $2.2 million, representing our final distribution from Rio Grande. Our recorded net asset balance of Rio Grande at December 1, 2009, was $22.7 million, consisting of cash of $3.1 million, $29.9 million in properties and equipment, net and $10.3 million in equity, representing BP, Plc’s 30% noncontrolling interest.
Cash flows from continuing and discontinued operations have been combined for presentation purposes in the Consolidated Statements of Cash Flows. For the six months ended June 30, 2009, net cash flows from our discontinued Rio Grande operations were $4.1 million.

 

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Note 3: Acquisitions
2010 Acquisitions
Tulsa East / Lovington Storage Asset Transaction
On March 31, 2010, we acquired from Holly certain storage assets for $88.6 million consisting of hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at Holly’s Tulsa refinery east facility.
In connection with this purchase, we amended our 15-year pipeline, tankage and loading rack throughput agreement with Holly (the “Holly PTTA”) that initially pertained to the logistics and storage assets acquired from an affiliate of Sinclair Oil Company (“Sinclair”) in December 2009. Under the amended Holly PTTA, Holly has agreed to transport, throughput and load volumes of product through our Tulsa east facility logistics and storage assets that will result in minimum annualized revenues to us of $27.2 million.
Also, as part of this same transaction, we acquired Holly’s asphalt loading rack facility located at its Navajo refinery facility in Lovington, New Mexico for $4.4 million and entered into a 15-year asphalt facility throughput agreement (the “Holly ATA”). Under the Holly ATA, Holly has agreed to throughput a minimum volume of products via our Lovington asphalt loading rack facility that will result in minimum annualized revenues to us of $0.5 million.
We are a controlled subsidiary of Holly. In accounting for these March 2010 acquisitions from Holly, we recorded total property and equipment at Holly’s cost basis of $39 million and the purchase price in excess of Holly’s basis in the assets of $54 million as a decrease to our partners’ equity.
2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, we acquired from Sinclair storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at its refinery located in Tulsa, Oklahoma for $79.2 million. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes and 1,373,609 of our common units having a fair value of $53.5 million. Separately, Holly, also a party to the transaction, acquired Sinclair’s Tulsa refinery.
With respect to this purchase, we recorded $30.2 million in properties and equipment, $49.1 million in goodwill and $0.2 million in other long-term liabilities. The value of the acquired assets, which does not include goodwill, is based on management’s fair value estimates using a cost approach methodology.
Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, we acquired from Holly two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects the Navajo refinery Lovington facility to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects our New Mexico crude oil gathering system to the Navajo refinery Lovington facility (the “Beeson Pipeline”).
Tulsa West Loading Racks Transaction
On August 1, 2009, we acquired from Holly certain truck and rail loading/unloading facilities located at Holly’s Tulsa refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa refinery onto rail cars and/or tanker trucks.
Lovington-Artesia Pipeline Transaction
On June 1, 2009, we acquired from Holly a newly constructed 16-inch intermediate pipeline for $34.2 million that runs 65 miles from the Navajo refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico.

 

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The Roadrunner and Beeson Pipelines, loading rack facilities and 16-inch intermediate pipeline discussed above were recorded at $95.1 million, representing Holly’s cost basis in the transferred assets. The $3.1 million purchase price in excess of Holly’s basis in the assets was recorded as a decrease to our partners’ equity.
SLC Pipeline Joint Venture Interest
On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system that we jointly own with Plains All American Pipeline, L.P. (“Plains”). The total cost of our investment in the SLC Pipeline was $28 million, consisting of the capitalized $25.5 million joint venture contribution and the $2.5 million finder’s fee paid to Holly that was expensed as acquisition costs.
Note 4: Financial Instruments
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and an interest rate swap. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturity of these instruments.
Our debt consists of outstanding principal under our revolving credit agreement (the “Credit Agreement”), our 6.25% senior notes due 2015 (the “6.25% Senior Notes”) and our 8.25% senior notes due 2018 (the “8.25% Senior Notes”). The $155 million carrying amount of outstanding debt under our Credit Agreement at June 30, 2010, approximates fair value as interest rates are reset frequently using current rates. The estimated fair values of our 6.25% Senior Notes and 8.25% Senior Notes were $173.9 million and $148.5 million, respectively, at June 30, 2010. These fair value estimates are based on market quotes provided from a third-party bank. See Note 8 for additional information on these instruments.
Fair Value Measurements
Fair value measurements are derived using inputs, assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. U.S. generally accepted accounting principles (“GAAP”) categorizes inputs used in fair value measurements into three broad levels as follows:
   
(Level 1) Quoted prices in active markets for identical assets or liabilities.
   
(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.
   
(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.
We have an interest rate swap that is measured at fair value on a recurring basis using Level 2 inputs that as of June 30, 2010 had a fair value of $11.1 million. With respect to this instrument, fair value is based on the net present value of expected future cash flows related to both variable and fixed rate legs of our interest rate swap agreement. Our measurement is computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input. See Note 8 for additional information on our interest rate swap.

 

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Note 5: Properties and Equipment
                 
    June 30,     December 31,  
    2010     2009  
    (In thousands)  
 
               
Pipelines and terminals (1)
  $ 495,321     $ 455,075  
Land and right of way
    25,247       25,230  
Other
    13,411       12,528  
Construction in progress
    12,775       10,484  
 
           
 
    546,754       503,317  
Less accumulated depreciation
    116,504       105,273  
 
           
 
  $ 430,250     $ 398,044  
 
           
     
(1)  
We periodically evaluate estimated useful lives of our properties and equipment. Effective January 1, 2010, we have revised the estimated useful lives of our terminal assets to 16 to 25 years. This change in estimated useful lives resulted in a $1.5 million reduction in depreciation expense for the six months ended June 30, 2010.
We capitalized $0.2 million and $0.7 million in interest related to major construction projects during the six months ended June 30, 2010 and 2009, respectively.
Note 6: Transportation Agreements
Our transportation agreements consist of the following:
   
The Alon pipelines and terminals agreement (the “Alon PTA”) represents a portion of the total purchase price of the Alon assets that was allocated based on an estimated fair value derived under an income approach. This asset is being amortized over 30 years ending 2035, the 15-year initial term of the Alon PTA plus the expected 15-year extension period.
   
The Holly crude pipelines and tankage agreement (the “Holly CPTA”) represents a portion of the total purchase price of certain crude pipelines and tankage assets acquired from Holly in 2008 that was allocated using a fair value based on the agreement’s expected contribution to our future earnings under an income approach. This asset is being amortized over 15 years ending 2023, the 15-year term of the Holly CPTA.
The carrying amounts of our transportation agreements are as follows:
                 
    June 30,     December 31,  
    2010     2009  
    (In thousands)  
 
               
Alon transportation agreement
  $ 59,933     $ 59,933  
Holly crude pipelines and tankage agreement
    74,231       74,231  
 
           
 
    134,164       134,164  
Less accumulated amortization
    22,201       18,728  
 
           
 
  $ 111,963     $ 115,436  
 
           
We have additional transportation agreements with Holly that relate to pipeline, terminal and tankage assets contributed to us or acquired from Holly. These transfers occurred while under common control of Holly, therefore, our basis in these assets reflect Holly’s historical cost and does not reflect a step-up in basis to fair value. These agreements have a recorded value of zero.
In addition, we have an agreement to provide transportation and storage services to Holly via our Tulsa logistics and storage assets acquired from Sinclair. Since this agreement is with Holly and not between Sinclair and us, there is no cost attributable to this agreement.

 

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Note 7: Employees, Retirement and Incentive Plans
Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., a Holly subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs are charged to us monthly in accordance with an omnibus agreement that we have with Holly. These employees participate in the retirement and benefit plans of Holly. Our share of retirement and benefit plan costs was $0.6 million for the three months ended June 30, 2010 and 2009, and $1.3 million and $1.2 million for the six months ended June 30, 2010 and 2009, respectively.
We have adopted an incentive plan (“Long-Term Incentive Plan”) for employees, consultants and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four components: restricted units, performance units, unit options and unit appreciation rights.
As of June 30, 2010, we have two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.3 million and $0.4 million for the three months ended June 30, 2010 and 2009, respectively, and $1.3 million and $0.9 million for the six months ended June 30, 2010 and 2009, respectively. We currently purchase units in the open market instead of issuing new units for settlement of restricted unit grants. At June 30, 2010, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 175,289 had not yet been granted.
Restricted Units
Under our Long-Term Incentive Plan, we grant restricted units to selected employees and directors who perform services for us, with vesting generally over a period of one to five years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant. The fair value of each restricted unit award is measured at the market price as of the date of grant and is amortized over the vesting period.
A summary of restricted unit activity and changes during the six months ended June 30, 2010 is presented below:
                                 
                    Weighted-        
            Weighted-     Average     Aggregate  
            Average     Remaining     Intrinsic  
            Grant-Date     Contractual     Value  
Restricted Units   Grants     Fair Value     Term     ($000)  
 
                               
Outstanding at January 1, 2010 (nonvested)
    53,271     $ 34.31                  
Granted
    31,355       42.59                  
Vesting and transfer of full ownership to recipients
    (34,645 )     38.94                  
Forfeited
    (1,226 )     34.28                  
 
                             
Outstanding at June 30, 2010 (nonvested)
    48,755     $ 36.35     0.9 year   $ 2,136  
 
                       
The fair value of restricted units that were vested and transferred to recipients during the six months ended June 30, 2010 and 2009 were $1.5 million and $0.9 million, respectively. As of June 30, 2010, there was $0.6 million of total unrecognized compensation costs related to nonvested restricted unit grants. That cost is expected to be recognized over a weighted-average period of 0.9 year.
During the six months ended June 30, 2010, we paid $2.3 million for the purchase of 53,952 of our common units in the open market for the recipients of our restricted unit grants.
Performance Units
Under our Long-Term Incentive Plan, we grant performance units to selected executives who perform services for us. Performance units granted in 2010 are payable based upon the growth in our distributable cash flow per common unit over the performance period, and vest over a period of three years. Performance units granted in 2009 and 2008 are payable based upon the growth in distributions on our common units during the requisite period, and vest over a period of three years. As of June 30, 2010, estimated share payouts for outstanding nonvested performance unit awards ranged from 110% to 120%.

 

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We granted 16,965 performance units to certain officers in March 2010. These units will vest over a three-year performance period ending December 31, 2012 and are payable in HEP common units. The number of units actually earned will be based on the growth of our distributable cash flow per common unit over the performance period, and can range from 50% to 150% of the number of performance units granted. The fair value of these performance units is based on the grant date closing unit price of $42.59 and will apply to the number of units ultimately awarded.
A summary of performance unit activity and changes during the six months ended June 30, 2010 is presented below:
         
    Payable  
Performance Units   In Units  
 
       
Outstanding at January 1, 2010 (nonvested)
    54,771  
Vesting and transfer of common units to recipients
    (11,785 )
Granted
    16,965  
Forfeited
    (536 )
 
     
Outstanding at June 30, 2010 (nonvested)
    59,415  
 
     
The fair value of performance units vested and transferred to recipients during the six months ended June 30, 2010 and 2009 was $0.5 million and $0.4 million, respectively. Based on the weighted average fair value at June 30, 2010 of $32.97, there was $1.1 million of total unrecognized compensation cost related to nonvested performance units. That cost is expected to be recognized over a weighted-average period of 1.5 years.
Note 8: Debt
Credit Agreement
We have a $300 million senior secured revolving Credit Agreement expiring in August 2011. The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. In addition, the Credit Agreement is available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $20 million sub-limit. Advances under the Credit Agreement that are designated for working capital are classified as short-term liabilities. Other advances under the Credit Agreement, including advances used for the financing of capital projects, are classified as long-term liabilities. During the six months ended June 30, 2010, we received advances totaling $39 million and repaid $90 million, resulting in the net repayment of $51 million in advances. As of June 30, 2010, we had $155 million outstanding under the Credit Agreement.
Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. Any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, are not significant.
We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days in each twelve-month period prior to the maturity date of the agreement. As of June 30, 2010, we had no working capital borrowings.
Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.50%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). At June 30, 2010, we were subject to an applicable margin of 1.75%. We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At June 30, 2010, we are subject to a .30% commitment fee on the $145 million unused portion of the Credit Agreement. The agreement expires in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will become due and payable.

 

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The Credit Agreement imposes certain requirements on us, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio and debt to EBITDA ratio. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.
Additionally, the Credit Agreement contains certain provisions whereby the lenders may accelerate payment of outstanding debt under certain circumstances.
Senior Notes
In March 2010, we issued $150 million in aggregate principal amount of 8.25% Senior Notes maturing March 15, 2018. A portion of the $147.5 million in net proceeds received was used to fund our $93 million purchase of the Tulsa and Lovington storage assets from Holly on March 31, 2010. Additionally, we used a portion to repay $42 million in outstanding Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital and capital expenditures.
Our 6.25% Senior Notes having an aggregate principal amount of $185 million mature March 1, 2015 and are registered with the SEC. The 6.25% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants, which we are subject to and currently in compliance with, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Senior Notes.
Indebtedness under the Senior Notes is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, are not significant.
The carrying amounts of our long-term debt are as follows:
                 
    June 30,     December 31,  
    2010     2009  
    (In thousands)  
Credit Agreement
  $ 155,000     $ 206,000  
 
               
6.25% Senior Notes
               
Principal
    185,000       185,000  
Unamortized discount
    (1,774 )     (1,964 )
Unamortized premium — dedesignated fair value hedge
    1,617       1,791  
 
           
 
    184,843       184,827  
 
           
 
               
8.25% Senior Notes
               
Principal
    150,000        
Unamortized discount
    (2,364 )      
 
           
 
    147,636        
 
           
 
               
Total long-term debt
  $ 487,479     $ 390,827  
 
           

 

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Interest Rate Risk Management
We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.
As of June 30, 2010, we have an interest rate swap that hedges our exposure to the cash flow risk caused by the effects of LIBOR changes on a $155 million Credit Agreement advance. This interest rate swap effectively converts $155 million of LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, which equals an effective interest rate of 5.49% as of June 30, 2010. The maturity date of this swap contract is February 28, 2013.
We have designated this interest rate swap as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that this interest rate swap is effective in offsetting the variability in interest payments on our $155 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedge on a quarterly basis to its fair value with the offsetting fair value adjustment to accumulated other comprehensive income. Also on a quarterly basis, we measure hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of our swap against the expected future interest payments on our $155 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. To date, we have had no ineffectiveness on our cash flow hedge.
In May 2010, we repaid $16 million of our Credit Agreement debt and also settled a corresponding portion of our interest rate swap agreement having a notional amount of $16 million for $1.1 million. Upon payment, we reduced our swap liability and reclassified a $1.1 million charge from accumulated other comprehensive loss to interest expense, representing the application of hedge accounting prior to settlement.
Additional information on our interest rate swap as of June 30, 2010 is as follows:
                                 
    Balance Sheet             Location of Offsetting     Offsetting  
Interest Rate Swap   Location     Fair Value     Balance     Amount  
    (In thousands)  
Liability
                               
Cash flow hedge — $155 million LIBOR based debt
  Other long-term liabilities   $ 11,122     Accumulated other comprehensive loss   $ 11,122  
 
                           
In the first quarter of 2010, we settled two interest rate swaps. We had an interest rate swap contract that effectively converted interest expense associated with $60 million of our 6.25% Senior Notes from fixed to variable rate debt (“Variable Rate Swap”). We had an additional interest rate swap contract that effectively unwound the effects of the Variable Rate Swap, converting $60 million of the previously hedged long-term debt back to fixed rate debt (“Fixed Rate Swap”), effectively fixing interest at a 4.75% rate. Upon settlement of the Variable Rate and Fixed Rate Swaps, we received $1.9 million and paid $3.6 million, respectively.
For the six months ended June 30, 2010, we recognized a $1.5 million charge to interest expense as a result of fair value adjustments to our interest rate swaps. For the six months ended June 30, 2009, fair value adjustments resulted in a $0.6 million decrease to interest expense.
We have a deferred hedge premium that relates to the application of hedge accounting to the Variable Rate Swap prior to its hedge dedesignation in 2008. This deferred hedge premium having a balance of $1.6 million at June 30, 2010, is being amortized as a reduction to interest expense over the remaining term of the 6.25% Senior Notes.

 

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Interest Expense and Other Debt Information
Interest expense consists of the following components:
                 
    June 30,     June 30,  
    2010     2009  
    (In thousands)  
Interest on outstanding debt:
               
Credit Agreement, net of interest on interest rate swap
  $ 4,726     $ 5,260  
6.25% Senior Notes, net of interest on interest rate swaps
    5,623       5,338  
8.25% Senior Notes
    3,816        
Partial settlement of interest rate swap — cash flow hedge
    1,076        
Net fair value adjustments to interest rate swaps
    1,464       (628 )
Net amortization of discount and deferred debt issuance costs
    458       353  
Commitment fees
    177       145  
 
           
Total interest incurred
    17,340       10,468  
 
               
Less capitalized interest
    247       661  
 
           
 
               
Net interest expense
  $ 17,093     $ 9,807  
 
           
 
               
Cash paid for interest (1)
  $ 14,192     $ 11,836  
 
           
     
(1)  
Net of cash received under our interest rate swap agreements of $1.9 million for the six months ended June 30, 2010 and 2009.
Note 9: Significant Customers
All revenues are domestic revenues, of which ninety-six percent are currently generated from our two largest customers: Holly and Alon. The major concentration of our petroleum product and crude oil pipeline systems’ revenues is derived from activities conducted in the southwest United States.
The following table presents the percentage of total revenues from continuing operations generated by each of these customers:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2010     2009     2010     2009  
Holly
    82 %     66 %     82 %     64 %
Alon
    14 %     29 %     14 %     30 %
Note 10: Related Party Transactions
Holly and Alon Agreements
We serve Holly’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:
   
Holly PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to the pipelines and terminal assets contributed to us by Holly upon our initial public offering in 2004);
   
Holly IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to the intermediate pipelines acquired from Holly in 2005 and 2009);
   
Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to the crude pipelines and tankage assets acquired from Holly in 2008);
   
Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east storage tank and loading rack facilities acquired from Sinclair in 2009 and from Holly in March 2010);

 

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Holly RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from Holly in 2009);
   
Holly ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west loading rack facilities acquired from Holly in 2009); and
   
Holly ATA (loading rack throughput agreement expiring in 2025 that relates to the Lovington asphalt loading rack facility acquired from Holly in March 2010).
Under these agreements, Holly agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a percentage change based upon the change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate based upon the percentage change in the PPI or the Federal Energy Regulatory Commission (“FERC”) index, but with the exception of the Holly IPA, generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically. Following the July 1, 2010 PPI adjustment, these agreements with Holly will result in minimum annualized payments to us of $132.4 million.
We also have a pipelines and terminals agreement with Alon expiring in 2020 under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate. Following the March 1, 2010 PPI adjustment, Alon’s minimum annualized commitment to us is $22.7 million.
If Holly or Alon fails to meet their minimum volume commitments under the agreements in any quarter, it will be required to pay us in cash the amount of any shortfall by the last day of the month following the end of the quarter. A shortfall payment under the Holly PTA, Holly IPA and Alon PTA may be applied as a credit in the following four quarters after minimum obligations are met.
We entered into an omnibus agreement with Holly in 2004 that Holly and we have amended and restated several times in connection with our past acquisitions from Holly with the last amendment and restatement occurring on March 31, 2010 (the “Omnibus Agreement”). Under certain provisions of the Omnibus Agreement, we pay Holly an annual administrative fee, currently $2.3 million, for the provision by Holly or its affiliates of various general and administrative services to us. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, which are separately charged to us by Holly. Also, we reimburse Holly and its affiliates for direct expenses they incur on our behalf.
Related party transactions with Holly are as follows:
 
Revenues received from Holly were $37.1 million and $25.1 million for the three months ended June 30, 2010 and 2009, respectively, and $70.7 million and $43.4 million for the six months ended June 30, 2010 and 2009, respectively.
 
Holly charged general and administrative services under the Omnibus Agreement of $0.6 million for the three months ended June 30, 2010 and 2009 and $1.2 million for the six months ended June 30, 2010 and 2009.
 
We reimbursed Holly for costs of employees supporting our operations of $4.6 million and $4 million for the three months ended June 30, 2010 and 2009, respectively, and $8.8 million and $8.6 million for the six months ended June 30, 2010 and 2009, respectively.
 
We paid Holly a $2.5 million finder’s fee in connection the acquisition of our 25% joint venture interest in the SLC Pipeline in the first quarter of 2009.

 

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We distributed $8.8 million and $7.1 million for the three months ended June 30, 2010 and 2009, respectively, to Holly as regular distributions on its common units, subordinated units and general partner interest, including general partner incentive distributions. We distributed $17.4 million and $14 million during the six months ended June 30, 2010 and 2009, respectively.
 
Accounts receivable from Holly were $16.7 million and $14.1 million at June 30, 2010 and December 31, 2009, respectively.
 
Accounts payable to Holly were $2.9 million and $2.4 million at June 30, 2010 and December 31, 2009, respectively.
 
Holly failed to meet its minimum volume commitment for each of the twenty quarters since inception of the Holly IPA. Through June 30, 2010, we have charged Holly $12.4 million for these shortfalls of which $0.7 million is included in affiliate accounts receivable at June 30, 2010 and December 31, 2009.
 
Revenues for the three and the six months ended June 30, 2010 include $0.5 million and $2.3 million of shortfalls billed under the Holly IPA in 2009 as Holly did not exceed its minimum volume commitment in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at June 30, 2010 and December 31, 2009, includes $3.2 million and $3.6 million, respectively, relating to the Holly IPA. It is possible that Holly may not exceed its minimum obligations under the Holly IPA to allow Holly to receive credit for any of the $3.2 million deferred at June 30, 2010.
 
We acquired the Tulsa east and Lovington storage assets, Roadrunner and Beeson Pipelines, Tulsa loading racks and a 16-inch intermediate pipeline from Holly in March 2010, December 2009, August 2009 and June 2009, respectively. See Note 3 for a description of these transactions.
Alon became a related party when it acquired all of our Class B subordinated units in connection with our acquisition of assets from them in February 2005. In May 2010, all of the conditions necessary to end the subordination period for the 937,500 Class B subordinated units originally issued to Alon were met and the units were converted into our common units on a one-for-one basis.
Related party transactions with Alon are as follows:
 
Revenues received from Alon were $4.6 million and $9.2 million for the three months ended June 30, 2010 and 2009, respectively, and $8.5 million and $17 million for the six months ended June 30, 2010 and 2009, respectively under the Alon PTA. Additionally, revenues received under a pipeline capacity lease agreement with Alon were $1.6 million and $1.7 million for three months ended June 30, 2010 and 2009, respectively, and $3.2 million and $3.4 million for the six months ended June 30, 2010 and 2009, respectively.
 
We distributed $0.7 million for the three months ended June 30, 2010 and 2009, and $1.5 million and $1.4 million for the six months ended June 30, 2010 and 2009, respectively, to Alon for distributions on its units.
 
Accounts receivable — trade include receivable balances from Alon of $4.5 million at June 30, 2010 and $4 million at December 31, 2009.
 
Revenues for the three and the six months ended June 30, 2010 include $1.1 million and $1.8 million, respectively, of shortfalls billed under the Alon PTA in 2010, as Alon did not exceed its minimum revenue obligation in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at June 30, 2010 and December 31, 2009 includes $7.8 million and $4.8 million, respectively, relating to the Alon PTA. It is possible that Alon may not exceed its minimum obligations under the Alon PTA to allow Alon to receive credit for any of the $7.8 million deferred at June 30, 2010.

 

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Note 11: Partners’ Equity
Holly currently holds 7,290,000 of our common units and the 2% general partner interest, which together constitutes a 34% ownership interest in us.
Issuances of units
We issued 1,373,609 of our common units having a value of $53.5 million to Sinclair as partial consideration of our total $79.2 million purchase of Sinclair’s Tulsa logistics assets in December 2009.
We issued in a public offering 2,185,000 of our common units priced at $35.78 per unit in November 2009. Aggregate net proceeds of $74.9 million were used to fund the cash portion of our December 2009 asset acquisitions, to repay outstanding borrowings under the Credit Agreement and for general partnership purposes.
Additionally, we issued in a public offering 2,192,400 of our common units priced at $27.80 per unit in May 2009. Net proceeds of $58.4 million were used to repay outstanding borrowings under the Credit Agreement and for general partnership purposes.
We received aggregate capital contributions of $3.8 million from our general partner to maintain its 2% general partner interest concurrent with the 2009 common unit issuances described above.
Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise $860 million through security offerings, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.
Allocations of Net Income
Net income attributable to Holly Energy Partners, L.P. is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions that are declared subsequent to quarter end. After the amount of incentive distributions is allocated to the general partner, the remaining net income attributable to HEP is generally allocated to the partners based on their weighted-average ownership percentage during the period.
The following table presents the allocation of the general partner interest in net income:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2010     2009     2010     2009  
    (In thousands, except per unit data)  
 
                               
General partner interest in net income
  $ 220     $ 304     $ 388     $ 392  
General partner incentive distribution
    2,689       1,545       5,167       2,750  
 
                       
Total general partner interest in net income attributable to HEP
  $ 2,909     $ 1,849     $ 5,555     $ 3,142  
 
                       
Cash Distributions
Our general partner, HEP Logistics Holdings, L.P., is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels.
On July 23, 2010, we announced our cash distribution for the first quarter of 2010 of $0.825 per unit. The distribution is payable on all common, subordinated, and general partner units and will be paid August 13, 2010 to all unitholders of record on August 3, 2010.

 

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The following table presents the allocation of our regular quarterly cash distributions to the general and limited partners for the periods in which they apply. Our distributions are declared subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid during the periods presented below.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2010     2009     2010     2009  
    (In thousands, except per unit data)  
 
                               
General partner interest
  $ 427     $ 328     $ 844     $ 611  
General partner incentive distribution
    2,689       1,545       5,167       2,750  
 
                       
 
                               
Total general partner distribution
    3,116       1,873       6,011       3,361  
 
                               
Limited partner distribution
    18,215       14,552       36,209       27,214  
 
                       
 
                               
Total regular quarterly cash distribution
  $ 21,331     $ 16,425     $ 42,220     $ 30,575  
 
                       
Cash distribution per unit applicable to limited partners
  $ 0.825     $ 0.785     $ 1.640     $ 1.560  
 
                       
As a master limited partnership, we distribute our available cash, which has historically exceeded our net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in our equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets transferred to us upon our initial public offering in 2004, the intermediate pipelines purchased from Holly in 2005 and the assets purchased from Holly in 2009 and March 2010 had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $214.4 million would have been recorded in our financial statements as increases to our properties and equipment and intangible assets instead of decreases to partners’ equity.
Comprehensive Income
We have other comprehensive income (losses) resulting from fair value adjustments to our cash flow hedge. Our comprehensive income is as follows:
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2010     2009     2010     2009  
    (In thousands)  
 
                               
Net income
  $ 13,435     $ 16,819     $ 24,137     $ 22,753  
Other comprehensive income (loss):
                               
Change in fair value of cash flow hedge
    (1,696 )     4,417       (3,057 )     4,267  
Reclassification adjustment to net income on partial settlement of cash flow hedge
    1,076             1,076        
 
                       
 
                               
Other comprehensive income (loss)
    (620 )     4,417       (1,981 )     4,267  
 
                       
Comprehensive income
    12,815       21,236       22,156       27,020  
Less noncontrolling interest in comprehensive income
          (427 )           (922 )
 
                       
Comprehensive income attributable to HEP unitholders
  $ 12,815     $ 20,809     $ 22,156     $ 26,098  
 
                       

 

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Note 12: Supplemental Guarantor/Non-Guarantor Financial Information
Obligations of Holly Energy Partners, L.P. (“Parent”) under the 6.25% Senior Notes and 8.25% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect wholly-owned subsidiaries (“Guarantor Subsidiaries”). These guarantees are full and unconditional.
We sold our 70% interest in Rio Grande on December 1, 2009; therefore, Rio Grande is no longer a subsidiary of HEP. Rio Grande (“Non-Guarantor”) was the only subsidiary that did not guarantee these obligations. Amounts attributable to Rio Grande prior to our sale are presented in discontinued operations.
The following financial information presents condensed consolidating balance sheets, statements of income, and statements of cash flows of the Parent, the Guarantor Subsidiaries and the Non-Guarantor. The information has been presented as if the Parent accounted for its ownership in the Guarantor Subsidiaries, and the Guarantor Subsidiaries accounted for the ownership of the Non-Guarantor, using the equity method of accounting.

 

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Condensed Consolidating Balance Sheet
                                 
            Guarantor              
June 30, 2010   Parent     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
ASSETS
                               
Current assets:
                               
Cash and cash equivalents
  $ 2     $ 2,804     $     $ 2,806  
Accounts receivable
          23,088             23,088  
Intercompany accounts receivable (payable)
    (35,489 )     35,489              
Prepaid and other current assets
    62       877             939  
 
                       
Total current assets
    (35,425 )     62,258             26,833  
 
                               
Properties and equipment, net
          430,250             430,250  
Investment in subsidiaries
    494,717             (494,717 )      
Transportation agreements, net
          111,963             111,963  
Goodwill
          49,109             49,109  
Investment in SLC Pipeline
          25,819             25,819  
Other assets
    1,242       600             1,842  
 
                       
Total assets
  $ 460,534     $ 679,999     $ (494,717 )   $ 645,816  
 
                       
 
                               
LIABILITIES AND PARTNERS’ EQUITY
                               
Current liabilities:
                               
Accounts payable
  $     $ 6,340     $     $ 6,340  
Accrued interest
    7,670       18             7,688  
Deferred revenue
          10,923             10,923  
Accrued property taxes
          990             990  
Other current liabilities
    574       27             601  
 
                       
Total current liabilities
    8,244       18,298             26,542  
 
                               
Long-term debt
    332,479       155,000             487,479  
Other long-term liabilities
          11,984             11,984  
Partners’ equity
    119,811       494,717       (494,717 )     119,811  
 
                       
Total liabilities and partners’ equity
  $ 460,534     $ 679,999     $ (494,717 )   $ 645,816  
 
                       
Condensed Consolidating Balance Sheet
                                 
            Guarantor              
December 31, 2009   Parent     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
ASSETS
                               
Current assets:
                               
Cash and cash equivalents
  $ 2     $ 2,506     $     $ 2,508  
Accounts receivable
          18,767             18,767  
Intercompany accounts receivable (payable)
    (76,855 )     76,855              
Prepaid and other current assets
    261       478             739  
Current assets of discontinued operations
          2,195             2,195  
 
                       
Total current assets
    (76,592 )     100,801             24,209  
 
                               
Properties and equipment, net
          398,044             398,044  
Investment in subsidiaries
    458,381             (458,381 )      
Transportation agreements, net
          115,436             115,436  
Goodwill
          49,109             49,109  
Investment in SLC Pipeline
          25,919             25,919  
Other assets
    3,267       861             4,128  
 
                       
Total assets
  $ 385,056     $ 690,170     $ (458,381 )   $ 616,845  
 
                       
 
                               
LIABILITIES AND PARTNERS’ EQUITY
                               
Current liabilities:
                               
Accounts payable
  $     $ 6,211     $     $ 6,211  
Accrued interest
    2,849       14             2,863  
Deferred revenue
          8,402             8,402  
Accrued property taxes
          1,072             1,072  
Other current liabilities
    961       296             1,257  
 
                       
Total current liabilities
    3,810       15,995             19,805  
 
                               
Long-term debt
    184,827       206,000             390,827  
Other long-term liabilities
    2,555       9,794             12,349  
Partners’ equity
    193,864       458,381       (458,381 )     193,864  
 
                       
Total liabilities and partners’ equity
  $ 385,056     $ 690,170     $ (458,381 )   $ 616,845  
 
                       

 

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Condensed Consolidating Statement of Income
                                 
            Guarantor              
Three months ended June 30, 2010   Parent     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                               
Affiliates
  $     $ 37,079     $     $ 37,079  
Third parties
          8,404             8,404  
 
                       
 
          45,483             45,483  
 
                               
Operating costs and expenses:
                               
Operations
          13,495             13,495  
Depreciation and amortization
          7,591             7,591  
General and administrative
    1,281       632             1,913  
 
                       
 
    1,281       21,718             22,999  
 
                       
 
                               
Operating income (loss)
    (1,281 )     23,765             22,484  
 
                               
Equity in earnings of subsidiaries
    20,833             (20,833 )      
Equity in earnings of SLC Pipeline
          544             544  
Interest income (expense)
    (6,117 )     (3,430 )           (9,547 )
Other
                       
 
                       
 
    14,716       (2,886 )     (20,833 )     (9,003 )
 
                       
 
                               
Income (loss) before income taxes
    13,435       20,879       (20,833 )     13,481  
 
                               
State income tax
          (46 )           (46 )
 
                       
 
                               
Net income
  $ 13,435     $ 20,833     $ (20,833 )   $ 13,435  
 
                       
Condensed Consolidating Statement of Income
                                         
            Guarantor     Non-              
Three months ended June 30, 2009   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                                       
Affiliates
  $     $ 25,064     $     $     $ 25,064  
Third parties
          12,935                   12,935  
 
                             
 
          37,999                   37,999  
 
                                       
Operating costs and expenses:
                                       
Operations
          10,631                   10,631  
Depreciation and amortization
          6,613                   6,613  
General and administrative
    1,287       510                   1,797  
 
                             
 
    1,287       17,754                   19,041  
 
                             
 
                                       
Operating income (loss)
    (1,287 )     20,245                   18,958  
 
                                       
Equity in earnings of subsidiaries
    19,554       996             (20,550 )      
Equity in earnings of SLC Pipeline
          423                   423  
Interest income (expense)
    (1,875 )     (2,527 )                 (4,402 )
Other
          65                   65  
 
                             
 
    17,679       (1,043 )           (20,550 )     (3,914 )
 
                             
 
                                       
Income (loss) from continuing operations before income taxes
    16,392       19,202             (20,550 )     15,044  
 
                                       
State income tax
          (93 )                 (93 )
 
                             
 
                                       
Income from continuing operations
    16,392       19,109             (20,550 )     14,951  
 
                                       
Income from discontinued operations
          445       1,423       (427 )     1,441  
 
                             
 
                                       
Net income
  $ 16,392     $ 19,554     $ 1,423     $ (20,977 )   $ 16,392  
 
                             

 

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Condensed Consolidating Statement of Income
                                 
            Guarantor              
Six months ended June 30, 2010   Parent     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                               
Affiliates
  $     $ 70,676     $     $ 70,676  
Third parties
          15,503             15,503  
 
                       
 
          86,179             86,179  
 
                               
Operating costs and expenses:
                               
Operations
          26,555             26,555  
Depreciation and amortization
          14,801             14,801  
General and administrative
    3,082       1,394             4,476  
 
                       
 
    3,082       42,750             45,832  
 
                       
Operating income (loss)
    (3,082 )     43,429             40,347  
 
                               
Equity in earnings of subsidiaries
    38,318             (38,318 )      
Equity in earnings of SLC Pipeline
          1,025             1,025  
Interest income (expense)
    (11,099 )     (5,989 )           (17,088 )
Other
          (7 )           (7 )
 
                       
 
    27,219       (4,971 )     (38,318 )     (16,070 )
 
                       
 
                               
Income (loss) before income taxes
    24,137       38,458       (38,318 )     24,277  
 
                               
State income tax
          (140 )           (140 )
 
                       
 
                               
Net income
  $ 24,137     $ 38,318     $ (38,318 )   $ 24,137  
 
                       
Condensed Consolidating Statement of Income
                                         
            Guarantor     Non-              
Six months ended June 30, 2009   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                                       
Affiliates
  $     $ 43,387     $     $     $ 43,387  
Third parties
          23,944                   23,944  
 
                             
 
          67,331                   67,331  
 
                                       
Operating costs and expenses:
                                       
Operations
          20,973                   20,973  
Depreciation and amortization
          12,629                   12,629  
General and administrative
    1,985       1,146                   3,131  
 
                             
 
    1,985       34,748                   36,733  
 
                             
Operating income (loss)
    (1,985 )     32,583                   30,598  
 
                                       
Equity in earnings of subsidiaries
    28,618       2,152             (30,770 )      
Equity in earnings of SLC Pipeline
          598                   598  
SLC Pipeline acquisition costs
          (2,500 )                 (2,500 )
Interest income (expense)
    (4,802 )     (4,997 )                 (9,799 )
Other
          65                   65  
 
                             
 
    23,816       (4,682 )           (30,770 )     (11,636 )
 
                             
 
                                       
Income (loss) from continuing operations before income taxes
    21,831       27,901             (30,770 )     18,962  
 
                                       
State income tax
          (166 )                 (166 )
 
                             
 
                                       
Income from continuing operations
    21,831       27,735             (30,770 )     18,796  
 
                                       
Income from discontinued operations
          883       3,074       (922 )     3,035  
 
                             
 
                                       
Net income
  $ 21,831     $ 28,618     $ 3,074     $ (31,692 )   $ 21,831  
 
                             

 

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Condensed Consolidating Statement of Cash Flows
                                 
            Guarantor              
Six months ended June 30, 2010   Parent     Subsidiaries     Eliminations     Consolidated  
    (in thousands)  
 
                               
Cash flows from operating activities
  $ (103,599 )   $ 148,785     $     $ 45,186  
 
                               
Cash flows from investing activities
                               
Additions to properties and equipment
          (4,487 )           (4,487 )
Acquisition of assets from Holly Corporation
          (39,040 )           (39,040 )
 
                       
 
          (43,527 )           (43,527 )
 
                       
 
                               
Cash flows from financing activities
                               
Net repayments under credit agreement
          (51,000 )           (51,000 )
Net proceeds from issuance of senior notes
    147,540                   147,540  
Purchase price in excess of transferred basis in assets acquired from Holly Corporation
          (53,960 )           (53,960 )
Distributions to HEP unitholders
    (41,312 )                 (41,312 )
Purchase of units for restricted grants
    (2,276 )                 (2,276 )
Deferred financing costs
    (353 )                 (353 )
 
                       
 
    103,599       (104,960 )           (1,361 )
 
                       
 
                               
Cash and cash equivalents
                               
Increase (decrease) for the period
          298             298  
Beginning of period
    2       2,506             2,508  
 
                       
 
                               
End of period
  $ 2     $ 2,804     $     $ 2,806  
 
                       
Condensed Consolidating Statement of Cash Flows
                                         
            Guarantor     Non-              
Six months ended June 30, 2009   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (in thousands)  
 
                                       
Cash flows from operating activities
  $ (31,418 )   $ 61,676     $ 3,392     $ (1,400 )   $ 32,250  
 
                                       
Cash flows from investing activities
                                       
Additions to properties and equipment
          (55,962 )     (64 )           (56,026 )
Investment in SLC Pipeline
          (25,500 )                 (25,500 )
 
                             
 
          (81,462 )     (64 )           (81,526 )
 
                             
 
                                       
Cash flows from financing activities
                                       
Net borrowings under credit agreement
          18,000                   18,000  
Proceeds from issuance of common units
    58,355                         58,355  
Capital contribution from general partner
    1,191                         1,191  
Distributions to HEP unitholders
    (27,968 )           (2,000 )     2,000       (27,968 )
Distributions to noncontrolling interest
                      (600 )     (600 )
Cost of issuing common units
    (160 )                         (160 )
Purchase of units for restricted grants
          (616 )                 (616 )
 
                             
 
    31,418       17,384       (2,000 )     1,400       48,202  
 
                             
 
                                       
Cash and cash equivalents
                                       
Increase (decrease) for the period
          (2,402 )     1,328             (1,074 )
Beginning of period
    2       3,706       1,561             5,269  
 
                             
End of period
  $ 2     $ 1,304     $ 2,889     $     $ 4,195  
 
                             

 

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HOLLY ENERGY PARTNERS, L.P.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Item 2, including but not limited to the sections on “Results of Operations” and “Liquidity and Capital Resources,” contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I on this Quarterly Report on Form 10-Q. In this document, the words “we,” “our,” “ours” and “us” refer to HEP and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.
OVERVIEW
Holly Energy Partners, L.P. is a Delaware limited partnership. We own and operate petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities that support Holly Corporation’s (“Holly”) refining and marketing operations in west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. Holly currently owns a 34% interest in us including the 2% general partner interest. We also own and operate refined product pipelines and terminals, located primarily in Texas, that service Alon’s (“Alon”) refinery in Big Spring, Texas. Additionally, we own a 25% joint venture interest in a 95-mile intrastate crude oil pipeline system (the “SLC Pipeline”) that serves refineries in the Salt Lake City area.
We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling refined products and other hydrocarbons and storing and providing other services at our storage tanks and terminals. We do not take ownership of products that we transport, terminal or store, and therefore, we are not directly exposed to changes in commodity prices.
2010 Acquisitions
Tulsa East / Lovington Storage Asset Transaction
On March 31, 2010, we acquired from Holly certain storage assets for $93 million, consisting of hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at Holly’s Tulsa refinery east facility and an asphalt loading rack facility located at Holly’s Navajo refinery facility in Lovington, New Mexico.
2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, we acquired from an affiliate of Sinclair Oil Company (“Sinclair”) storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at its refinery located in Tulsa, Oklahoma for $79.2 million.
Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, we acquired from Holly two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects the Navajo refinery Lovington facility to a terminus of Centurion Pipeline L.P.’s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects our New Mexico crude oil gathering system to the Navajo refinery Lovington facility (the “Beeson Pipeline”).
Tulsa Loading Racks Transaction
On August 1, 2009, we acquired from Holly certain truck and rail loading/unloading facilities located at Holly’s Tulsa refinery west facility for $17.5 million. The racks load refined products and lube oils produced at the Tulsa refinery onto rail cars and/or tanker trucks.

 

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Lovington-Artesia Pipeline Transaction
On June 1, 2009, we acquired from Holly a newly constructed 16-inch intermediate pipeline for $34.2 million that runs 65 miles from the Navajo Refinery’s crude oil distillation and vacuum facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico.
SLC Pipeline Joint Venture Interest
On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system that we jointly own with Plains All American Pipeline, L.P. (“Plains”). The total cost of our investment in the SLC Pipeline was $28 million, consisting of the capitalized $25.5 million joint venture contribution and the $2.5 million finder’s fee paid to Holly that was expensed as acquisition costs.
Holly Capacity Expansion
Also in March 2009 Holly, our largest customer, completed a 15,000 barrels per stream day (“bpsd”) capacity expansion of its Navajo refinery increasing refining capacity to 100,000 bpsd, or by 18%.
Rio Grande Pipeline Sale
On December 1, 2009, we sold our 70% interest in the Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35 million. Accordingly, the results of operations of Rio Grande are presented in discontinued operations.
Agreements with Holly Corporation and Alon
We serve Holly’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:
   
Holly PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to the pipelines and terminal assets contributed to us by Holly upon our initial public offering in 2004);
   
Holly IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to the intermediate pipelines acquired from Holly in 2005 and 2009);
   
Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to the crude pipelines and tankage assets acquired from Holly in 2008);
   
Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east storage tank and loading rack facilities acquired from Sinclair in 2009 and from Holly in March 2010);
   
Holly RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from Holly in 2009);
   
Holly ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west loading rack facilities acquired from Holly in 2009); and
   
Holly ATA (loading rack throughput agreement expiring in 2025 that relates to the Lovington asphalt loading rack facility acquired from Holly in March 2010).
Under these agreements, Holly agreed to transport, store and throughput volumes of refined product and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in minimum annual payments to us. These minimum annual payments or revenues will be adjusted each year at a percentage change based upon the change in the Producer Price Index (“PPI”) but will not decrease as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate based upon the percentage change in the PPI or Federal Energy Regulatory Commission (“FERC”) index, but with the exception of the Holly IPA, generally will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed periodically.
We also have a pipelines and terminals agreement with Alon expiring in 2020 under which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but not below the initial tariff rate.

 

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At July 1, 2010, contractual minimums under our long-term service agreements are as follows:
                 
    Minimum Annualized          
    Commitment          
Agreement   (In millions)     Year of Maturity   Contract Type
 
               
Holly PTA
  $ 43.7     2019   Minimum revenue commitment
Holly IPA
    20.7     2024   Minimum revenue commitment
Holly CPTA
    28.4     2023   Minimum revenue commitment
Holly PTTA
    27.2     2024   Minimum revenue commitment
Holly RPA
    9.2     2024   Minimum revenue commitment
Holly ETA
    2.7     2024   Minimum revenue commitment
Holly ATA
    0.5     2025   Minimum revenue commitment
Alon PTA
    22.7     2020   Minimum volume commitment
Alon capacity lease
    6.4     Various   Capacity lease
 
             
 
               
Total
  $ 161.5          
 
             
A significant reduction in revenues under these agreements would have a material adverse effect on our results of operations.
We entered into an omnibus agreement with Holly in 2004 that Holly and we have amended and restated several times in connection with our past acquisitions from Holly with the last amendment and restatement occurring on March 31, 2010 (the “Omnibus Agreement”). Under certain provisions of the Omnibus Agreement, we pay Holly an annual administrative fee, currently $2.3 million, for the provision by Holly or its affiliates of various general and administrative services to us. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, which are separately charged to us by Holly. Also, we reimburse Holly and its affiliates for direct expenses they incur on our behalf.

 

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RESULTS OF OPERATIONS (Unaudited)
Income, Distributable Cash Flow and Volumes
The following tables present income, distributable cash flow and volume information for the three and the six months ended June 30, 2010 and 2009.
                         
    Three Months Ended     Change  
    June 30,     from  
    2010     2009     2009  
    (In thousands, except per unit data)  
Revenues
                       
Pipelines:
                       
Affiliates — refined product pipelines
  $ 12,067     $ 11,366     $ 701  
Affiliates — intermediate pipelines
    4,964       4,302       662  
Affiliates — crude pipelines
    9,728       6,751       2,977  
 
                 
 
    26,759       22,419       4,340  
Third parties — refined product pipelines
    6,455       11,098       (4,643 )
 
                 
 
    33,214       33,517       (303 )
 
                       
Terminals and loading racks:
                       
Affiliates
    10,320       2,645       7,675  
Third parties
    1,949       1,837       112  
 
                 
 
    12,269       4,482       7,787  
 
                 
Total revenues
    45,483       37,999       7,484  
 
                       
Operating costs and expenses
                       
Operations
    13,495       10,631       2,864  
Depreciation and amortization
    7,591       6,613       978  
General and administrative
    1,913       1,797       116  
 
                 
 
    22,999       19,041       3,958  
 
                 
 
                       
Operating income
    22,484       18,958       3,526  
 
                       
Equity in earnings of SLC Pipeline
    544       423       121  
Interest income
    2       2        
Interest expense, including amortization
    (9,549 )     (4,404 )     (5,145 )
Other
          65       (65 )
 
                 
 
    (9,003 )     (3,914 )     (5,089 )
 
                 
 
                       
Income from continuing operations before income taxes
    13,481       15,044       (1,563 )
 
                       
State income tax
    (46 )     (93 )     47  
 
                 
 
                       
Income from continuing operations
    13,435       14,951       (1,516 )
 
                       
Income from discontinued operations, net of noncontrolling interest of $427 (1)
          1,441       (1,441 )
 
                 
 
                       
Net income
    13,435       16,392       (2,957 )
 
                       
Less general partner interest in net income, including incentive distributions (2)
    2,909       1,849       1,060  
 
                 
 
                       
Limited partners’ interest in net income
  $ 10,526     $ 14,543     $ (4,017 )
 
                 
 
                       
Limited partners’ earnings per unit — basic and diluted (2)
                       
Income from continuing operations
  $ 0.48     $ 0.74     $ (0.26 )
Income from discontinued operations
          0.08       (0.08 )
 
                 
Net income
  $ 0.48     $ 0.82     $ (0.34 )
 
                 
 
                       
Weighted average limited partners’ units outstanding
    22,079       17,789       4,290  
 
                 
 
                       
EBITDA (3)
  $ 30,619     $ 27,759     $ 2,860  
 
                 
 
                       
Distributable cash flow (4)
  $ 22,673     $ 16,415     $ 6,258  
 
                 
 
                       
Volumes from continuing operations (bpd) (1)
                       
Pipelines:
                       
Affiliates — refined product pipelines
    98,464       94,738       3,726  
Affiliates — intermediate pipelines
    86,140       70,543       15,597  
Affiliates — crude pipelines
    141,263       142,598       (1,335 )
 
                 
 
    325,867       307,879       17,988  
Third parties — refined product pipelines
    34,844       43,854       (9,010 )
 
                 
 
    360,711       351,733       8,978  
 
                       
Terminals and loading racks:
                       
Affiliates
    186,515       115,221       71,294  
Third parties
    37,902       40,742       (2,840 )
 
                 
 
    224,417       155,963       68,454  
 
                 
Total for pipelines and terminal assets (bpd)
    585,128       507,696       77,432  
 
                 

 

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    Six Months Ended     Change  
    June 30,     from  
    2010     2009     2009  
    (In thousands, except per unit data)  
Revenues
                       
Pipelines:
                       
Affiliates — refined product pipelines
  $ 23,547     $ 18,919     $ 4,628  
Affiliates — intermediate pipelines
    10,756       6,068       4,688  
Affiliates — crude pipelines
    19,133       13,652       5,481  
 
                 
 
    53,436       38,639       14,797  
Third parties — refined product pipelines
    11,859       20,573       (8,714 )
 
                 
 
    65,295       59,212       6,083  
 
                       
Terminals and loading racks:
                       
Affiliates
    17,240       4,748       12,492  
Third parties
    3,644       3,371       273  
 
                 
 
    20,884       8,119       12,765  
 
                 
Total revenues
    86,179       67,331       18,848  
 
                       
Operating costs and expenses
                       
Operations
    26,555       20,973       5,582  
Depreciation and amortization
    14,801       12,629       2,172  
General and administrative
    4,476       3,131       1,345  
 
                 
 
    45,832       36,733       9,099  
 
                 
 
                       
Operating income
    40,347       30,598       9,749  
 
                       
Equity in earnings of SLC Pipeline
    1,025       598       427  
SLC Pipeline acquisition costs
          (2,500 )     2,500  
Interest income
    5       8       (3 )
Interest expense, including amortization
    (17,093 )     (9,807 )     (7,286 )
Other
    (7 )     65       (72 )
 
                 
 
    (16,070 )     (11,636 )     (4,434 )
 
                 
 
                       
Income from continuing operations before income taxes
    24,277       18,962       5,315  
 
                       
State income tax
    (140 )     (166 )     26  
 
                 
 
                       
Income from continuing operations
    24,137       18,796       5,341  
 
                       
Income from discontinued operations, net of noncontrolling interest of $922 (1)
          3,035       (3,035 )
 
                 
 
                       
Net income
    24,137       21,831       2,306  
 
                       
Less general partner interest in net income, including incentive distributions (2)
    5,555       3,142       2,413  
 
                 
 
                       
Limited partners’ interest in net income
  $ 18,582     $ 18,689     $ (107 )
 
                 
 
                       
Limited partners’ earnings per unit — basic and diluted (2)
                       
Income from continuing operations
  $ 0.84     $ 0.92     $ (0.08 )
Income from discontinued operations
          0.18       (0.18 )
 
                 
Net income
  $ 0.84     $ 1.10     $ (0.26 )
 
                 
 
                       
Weighted average limited partners’ units outstanding
    22,079       17,058       5,021  
 
                 
 
                       
EBITDA (3)
  $ 56,166     $ 44,943     $ 11,223  
 
                 
 
                       
Distributable cash flow (4)
  $ 42,831     $ 30,999     $ 11,832  
 
                 
 
                       
Volumes from continuing operations (bpd) (1)
                       
Pipelines:
                       
Affiliates — refined product pipelines
    95,937       78,628       17,309  
Affiliates — intermediate pipelines
    82,649       52,520       30,129  
Affiliates — crude pipelines
    138,094       132,459       5,635  
 
                 
 
    316,680       263,607       53,073  
Third parties — refined product pipelines
    32,850       46,557       (13,707 )
 
                 
 
    349,530       310,164       39,366  
 
                       
Terminals and loading racks:
                       
Affiliates
    175,218       99,118       76,100  
Third parties
    36,381       42,067       (5,686 )
 
                 
 
    211,599       141,185       70,414  
 
                 
Total for pipelines and terminal assets (bpd)
    561,129       451,349       109,780  
 
                 
     
(1)  
On December 1, 2009, we sold our 70% interest in Rio Grande. Results of operations of Rio Grande are presented in discontinued operations. Pipeline volume information excludes volumes attributable to Rio Grande.

 

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(2)  
Net income is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. Net income allocated to the general partner includes incentive distributions declared subsequent to quarter end. Net income attributable to the limited partners is divided by the weighted average limited partner units outstanding in computing the limited partners’ per unit interest in net income.
 
(3)  
EBITDA is calculated as net income plus (i) interest expense, net of interest income, (ii) state income tax and (iii) depreciation and amortization. EBITDA is not a calculation based upon GAAP. However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements, with the exception of EBITDA from discontinued operations. EBITDA should not be considered as an alternative to net income or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA also is used by our management for internal analysis and as a basis for compliance with financial covenants.
 
   
Set forth below is our calculation of EBITDA.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2010     2009     2010     2009  
    (In thousands)  
 
                               
Income from continuing operations
  $ 13,435     $ 14,951     $ 24,137     $ 18,796  
 
                               
Add (subtract):
                               
Interest expense
    8,209       5,071       14,095       10,082  
Amortization of discount and deferred debt issuance costs
    264       177       458       353  
Increase in interest expense — change in fair value of interest rate swaps and swap settlement costs
    1,076       (844 )     2,540       (628 )
Interest income
    (2 )     (2 )     (5 )     (8 )
State income tax
    46       93       140       166  
Depreciation and amortization
    7,591       6,613       14,801       12,629  
EBITDA from discontinued operations
          1,700             3,553  
 
                       
 
                               
EBITDA
  $ 30,619     $ 27,759     $ 56,166     $ 44,943  
 
                       
     
(4)  
Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts separately presented in our consolidated financial statements, with the exception of equity in excess cash flows over earnings of SLC Pipeline, maintenance capital expenditures and distributable cash flow from discontinued operations. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It also is used by management for internal analysis and our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating.

 

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Set forth below is our calculation of distributable cash flow.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2010     2009     2010     2009  
    (In thousands)  
Income from continuing operations
  $ 13,435     $ 14,951     $ 24,137     $ 18,796  
       
Add (subtract):
                               
Depreciation and amortization
    7,591       6,613       14,801       12,629  
Amortization of discount and deferred debt issuance costs
    264       177       458       353  
Increase in interest expense — change in fair value of interest rate swaps and swap settlement costs
    1,076       (844 )     2,540       (628 )
Equity in excess cash flows over earnings of SLC Pipeline
    174       167       352       220  
Increase (decrease) in deferred revenue
    1,414       (5,031 )     2,521       (4,669 )
SLC Pipeline acquisition costs*
                      2,500  
Maintenance capital expenditures**
    (1,281 )     (1,299 )     (1,978 )     (1,717 )
Distributable cash flow from discontinued operations
          1,681             3,515  
 
                       
       
Distributable cash flow
  $ 22,673     $ 16,415     $ 42,831     $ 30,999  
 
                       
     
*  
We expensed the $2.5 million finder’s fee associated with our joint venture agreement with Plains that closed in March 2009. These costs directly relate to our interest in the new joint venture pipeline and are similar to expansion capital expenditures; accordingly, we have added back these costs to arrive at distributable cash flow.
 
**  
Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations.
                 
    June 30,     December 31,  
    2010     2009  
    (In thousands)  
Balance Sheet Data
               
 
               
Cash and cash equivalents
  $ 2,806     $ 2,508  
Working capital
  $ 291     $ 4,404  
Total assets
  $ 645,816     $ 616,845  
Long-term debt (5)
  $ 487,479     $ 390,827  
Partners’ equity (6)
  $ 119,811     $ 193,864  
     
(5)  
Includes $155 million and $206 million of credit agreement advances at June 30, 2010 and December 31, 2009, respectively.
 
(6)  
As a master limited partnership, we distribute our available cash, which historically has exceeded our net income because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets transferred to us upon our initial public offering in 2004, the intermediate pipelines purchased from Holly in 2005, and the assets purchased from Holly in 2009 and March 2010 had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $214.4 million would have been recorded in our financial statements as increases to our properties and equipment and intangible assets instead of decreases to partners’ equity.

 

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Results of Operations — Three Months Ended June 30, 2010 Compared with Three Months Ended June 30, 2009
Summary
Income from continuing operations for the three months ended June 30, 2010 was $13.4 million, a $1.5 million decrease compared to the three months ended June 30, 2009. This decrease in overall earnings is due principally to a decrease in previously deferred revenue realized, a decrease in third-party shipments and increased interest expense.
Revenues for the three months ended June 30, 2010 include the recognition of $1.6 million of prior shortfalls billed to shippers in 2009 as they did not meet their minimum volume commitments in any of the subsequent four quarters. Revenues of $3.1 million relating to deficiency payments associated with certain guaranteed shipping contracts were deferred during the three months ended June 30, 2010. Such deferred revenue will be recognized in 2010 either as payment for shipments in excess of guaranteed levels or when shipping rights expire unused after a twelve-month period.
Revenues
Total revenues from continuing operations for the three months ended June 30, 2010 were $45.5 million, a $7.5 million increase compared to the three months ended June 30, 2009. This is due principally to revenues attributable to our 2009 and March 2010 asset acquisitions and higher tariff rates on affiliate shipments. These factors were partially offset by a $4 million decrease in previously deferred revenue realized and a decrease in third-party shipments.
Revenues from our refined product pipelines were $18.5 million, a decrease of $3.9 million compared to the three months ended June 30, 2009. This decrease is due principally to a $3.7 million decrease in previously deferred revenue realized combined with an overall decrease in refined product shipments. Volumes on our refined product pipelines averaged 133.3 thousand barrels per day (“mbpd”) compared to 138.6 mbpd for the same period last year, reflecting a decline in third-party shipments that was partially offset by an increase in affiliate shipments.
Revenues from our intermediate pipelines were $5 million, an increase of $0.7 million compared to the three months ended June 30, 2009. This increase is due principally to volumes shipped on our 16-inch intermediate pipeline acquired in June 2009 that was partially offset by a $0.4 million decrease in previously deferred revenue realized. Shipments on our intermediate product pipeline system increased to an average of 86.1 mbpd compared to 70.5 mbpd for the same period last year.
Revenues from our crude pipelines were $9.7 million, an increase of $3 million compared to the three months ended June 30, 2009. This increase is due principally to $2.3 million in revenues attributable to our Roadrunner Pipeline agreement entered into in December 2009. Volumes on our crude pipelines averaged 141.3 mbpd compared to 142.6 mbpd for the same period last year.
Revenues from terminal, tankage and loading rack fees were $12.3 million, an increase of $7.8 million compared to the three months ended June 30, 2009. This increase includes $7.5 million in revenues attributable to volumes transferred and stored at our Tulsa facilities. Refined products terminalled in our facilities increased to an average of 224.4 mbpd compared to 156 mbpd for the same period last year.
Operations Expense
Operations expense for the three months ended June 30, 2010 increased by $2.9 million compared to the three months ended June 30, 2009. This increase was due principally to costs attributable to overall higher throughput volumes, including those from our 2009 and March 2010 asset acquisitions, and higher maintenance and payroll expense.
Depreciation and Amortization
Depreciation and amortization for the three months ended June 30, 2010 increased by $1 million compared to the three months ended June 30, 2009. This was due to increased depreciation attributable to our 2009 and March 2010 asset acquisitions and capital projects. Additionally, effective January 1, 2010, we revised the estimated useful lives of our terminal assets to 16 to 25 years resulting in a $0.8 million reduction in depreciation expense for the three months ended June 30, 2010.

 

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General and Administrative
General and administrative costs for the three months ended June 30, 2010 increased by $0.1 million compared to the three months ended June 30, 2009.
Equity in Earnings of SLC Pipeline
Our equity in earnings of the SLC Pipeline were $0.5 million and $0.4 million for the three months ended June 30, 2010 and 2009, respectively.
Interest Expense
Interest expense for the three months ended June 30, 2010 totaled $9.5 million, an increase of $5.1 million compared to the three months ended June 30, 2009. This increase reflects interest on our 8.25% senior notes and costs of $1.1 million from a partial settlement of an interest rate swap. For the three months ended June 30, 2009, fair value adjustments to our interest rate swaps resulted in a $0.8 million reduction in interest expense. Excluding the effects of these fair value adjustments, our aggregate effective interest rate was 7.7% for the three months ended June 30, 2010 compared to 5.3% for 2009, reflecting interest on our 8.25% senior notes issued in March 2010.
State Income Tax
We recorded state income taxes of $46,000 and $93,000 for the three months ended June 30, 2010 and 2009, respectively, which are solely attributable to the Texas margin tax.
Discontinued Operations
We sold our interest in Rio Grande on December 1, 2009. Income from discontinued operations for the three months ended June 30, 2009 consists of earnings generated by Rio Grande of $1.4 million for the second quarter of 2009, presented net of earnings attributable to noncontrolling interest holders of $0.4 million.
Results of Operations — Six Months Ended June 30, 2010 Compared with Six Months Ended June 30, 2009
Summary
Income from continuing operations for the six months ended June 30, 2010 was $24.1 million, a $5.3 million increase compared to the six months ended June 30, 2009. This increase in overall earnings is due principally to overall increased shipments on our pipeline systems, earnings attributable to our 2009 and March 2010 asset acquisitions and higher tariff rates on affiliate shipments. These factors were partially offset by increased operating costs and expenses, and interest expense.
Revenues for the six months ended June 30, 2010 include the recognition of $4.1 million of prior shortfalls billed to shippers in 2009 as they did not meet their minimum volume commitments in any of the subsequent four quarters. Revenues of $6.6 million relating to deficiency payments associated with certain guaranteed shipping contracts were deferred during the six months ended June 30, 2010. Such deferred revenue will be recognized in 2010 either as payment for shipments in excess of guaranteed levels or when shipping rights expire unused after a twelve-month period.

 

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Revenues
Total revenues from continuing operations for the six months ended June 30, 2010 were $86.2 million, an $18.8 million increase compared to the six months ended June 30, 2009. This increase is due principally to our recent asset acquisitions and higher tariffs on affiliate shipments, partially offset by a $4.7 million decrease in previously deferred revenue realized. On a year-to-date basis, overall pipeline shipments were up 13%, reflecting increased affiliate volumes attributable to Holly’s first quarter of 2009 Navajo refinery expansion, including volumes shipped on our new 16-inch intermediate and Beeson pipelines, partially offset by a decrease in third-party shipments. Additionally, prior year affiliate shipments reflect lower volumes as a result of production downtime during a major maintenance turnaround of the Navajo refinery during the first quarter of 2009.
Revenues from our refined product pipelines were $35.4 million, a decrease of $4.1 million compared to the six months ended June 30, 2009. This decrease is due principally to a $5.9 million decrease in previously deferred revenue realized that was partially offset by a slight increase in refined product shipments. Volumes on our refined product pipeline system averaged 128.8 mbpd compared to 125.2 mbpd for the same period last year reflecting an increase in affiliate shipments, partially offset by a decline in third-party shipments.
Revenues from our intermediate pipelines were $10.8 million, an increase of $4.7 million compared to the six months ended June 30, 2009. This increase includes a $1.2 million increase in previously deferred revenue realized. Additionally, shipments on our intermediate product pipeline system increased to an average of 82.6 mbpd compared to 52.5 mbpd for the same period last year reflecting volumes shipped on our 16-inch intermediate pipeline acquired in June 2009.
Revenues from our crude pipelines were $19.1 million, an increase of $5.5 million compared to the six months ended June 30, 2009. This increase is due principally to $4.6 million in revenues attributable to our Roadrunner Pipeline agreement entered into in December 2009. Additionally, shipments on our crude pipeline system increased to an average of 138.1 mbpd during the six months ended June 30, 2010 compared to 132.5 mbpd for the same period last year reflecting increased affiliate shipments.
Revenues from terminal, tankage and loading rack fees were $20.9 million, an increase of $12.8 million compared to the six months ended June 30, 2009. This increase includes $11.9 million in revenues attributable to volumes transferred and stored at our Tulsa facilities acquired in 2009 and March 2010. Refined products terminalled in our facilities increased to an average of 211.6 mbpd compared to 141.2 mbpd for the same period last year.
Operations Expense
Operations expense for the six months ended June 30, 2010 increased by $5.6 million compared to the six months ended June 30, 2009. This increase was due principally to costs attributable to overall higher throughput volumes, including those from our recent asset acquisitions, and higher maintenance and payroll expense.
Depreciation and Amortization
Depreciation and amortization for the six months ended June 30, 2010 increased by $2.2 million compared to the six months ended June 30, 2009. This was due to increased depreciation attributable to our 2009 and March 2010 asset acquisitions and capital projects. Additionally, effective January 1, 2010, we revised the estimated useful lives of our terminal assets to 16 to 25 years resulting in a $1.5 million reduction in depreciation expense for the six months ended June 30, 2010.
General and Administrative
General and administrative costs for the six months ended June 30, 2010 increased by $1.3 million compared to the six months ended June 30, 2009, due principally to increased professional fees, including costs attributable to our March 2010 asset acquisitions.

 

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Equity in Earnings of SLC Pipeline
The SLC Pipeline commenced pipeline operations effective March 2009. Our equity in earnings of the SLC Pipeline was $1 million and $0.6 million for the six months ended June 30, 2010 and 2009, respectively.
SLC Pipeline Acquisition Costs
We incurred a $2.5 million finder’s fee in connection with the acquisition our SLC Pipeline joint venture interest in March 2009. As a result of accounting requirements, we were required to expense rather than capitalize these direct acquisition costs.
Interest Expense
Interest expense for the six months ended June 30, 2010 totaled $17.1 million, an increase of $7.3 million compared to the six months ended June 30, 2009. This increase reflects interest on our 8.25% senior notes and costs of $1.1 million from a partial settlement of an interest rate swap. Fair value adjustments to our interest rate swaps resulted in a $1.5 million non-cash charge to interest expense for the six months ended June 30, 2010 compared to a $0.6 million non-cash reduction for the six months ended June 30, 2009. Excluding the effects of these fair value adjustments, our aggregate effective interest rate was 6.8% for the six months ended June 30, 2010 compared to 5.3% for 2009 reflecting interest on our 8.25% senior notes issued in March 2010.
State Income Tax
We recorded state income taxes of $0.1 million and $0.2 million for the six months ended June 30, 2010 and 2009, respectively, which are solely attributable to the Texas margin tax.
Discontinued Operations
We sold our interest in Rio Grande on December 1, 2009. Income from discontinued operations for the six months ended June 30, 2009 consists of earnings generated by Rio Grande of $3 million for the first six months of 2009, presented net of earnings attributable to noncontrolling interest holders of $0.9 million.
LIQUIDITY AND CAPITAL RESOURCES
Overview
We have a $300 million senior secured revolving credit agreement expiring in August 2011 (the “Credit Agreement”). The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital and for general partnership purposes. In addition, the Credit Agreement is available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $20 million sub-limit. During the six months ended June 30, 2010, we received advances totaling $39 million and repaid $90 million, resulting in the net repayment of $51 million in advances. As of June 30, 2010, we had $155 million outstanding under the Credit Agreement.
In March 2010, we issued $150 million in aggregate principal amount of 8.25% senior notes maturing March 15, 2018 (the “8.25% Senior Notes”). A portion of the $147.5 million in net proceeds received was used to fund our $93 million purchase of the Tulsa and Lovington storage assets from Holly on March 31, 2010. Additionally, we used a portion to repay $42 million in outstanding Credit Agreement borrowings, with the remaining proceeds available for general partnership purposes, including working capital and capital expenditures. In addition, we have outstanding $185 million in aggregate principal amount of 6.25% senior notes maturing March 1, 2015 (the “6.25% Senior Notes”) that are registered with the SEC.

 

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Under our registration statement filed with the SEC using a “shelf” registration process, we currently have the ability to raise $860 million through security offerings, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities would be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.
We believe our current cash balances, future internally generated funds and funds available under the Credit Agreement will provide sufficient resources to meet our working capital liquidity needs for the foreseeable future.
In February and May 2010 we paid regular quarterly cash distributions of $0.805 and $0.815, on all units in an aggregate amount of $41.3 million. Included in these distributions were $4.7 million of payments to the general partner as an incentive distribution.
Cash flows from continuing and discontinued operations have been combined for presentation purposes in the Consolidated Statements of Cash Flows. For the six months ended June 30, 2009, net cash flows from our discontinued Rio Grande operations were $4.1 million.
Cash and cash equivalents increased by $0.3 million during the six months ended June 30, 2010. Cash flows provided by operating activities of $45.2 million exceeded the combined cash flows used for investing and financing activities of $43.5 million and $1.4 million, respectively. Working capital for the six months ended June 30, 2010 decreased by $4.1 million.
Cash Flows — Operating Activities
Cash flows from operating activities increased by $12.9 million from $32.3 million for the six months ended June 30, 2009 to $45.2 million for the six months ended June 30, 2010. This increase is due principally to $18 million in additional cash collections from our major customers, resulting principally from increased revenues, partially offset by year-over-year changes in payments attributable to costs of increased operations.
Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Under certain agreements with these shippers, they have the right to recapture these amounts if future volumes exceed minimum levels. For the six months ended June 30, 2010, we received cash payments of $6.2 million under these commitments. We billed $4.1 million during the six months ended June 30, 2009 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the six months ended June 30, 2010. Another $3.1 million is included in our accounts receivable at June 30, 2010 related to shortfalls that occurred during the second quarter of 2010.
Cash Flows — Investing Activities
Cash flows used for investing activities decreased by $38 million from $81.5 million for the six months ended June 30, 2009 to $43.5 million for the six months ended June 30, 2010. During the six months ended June 30, 2010, we acquired storage assets from Holly for $39 million and invested $4.5 million in additions to properties and equipment. For the six months ended June 30, 2009, we acquired Holly’s 16-inch intermediate pipeline and our SLC Pipeline joint venture interest costing $34.2 million and $25.5 million, respectively, and invested $21.8 million in additions to properties and equipment.
Cash Flows — Financing Activities
Cash flows used for financing activities was $1.4 million compared to cash provided by financing activities of $48.2 for the six months ended June 30, 2009, a decrease of $49.6 million. During the six months ended June 30, 2010, we received $39 million and repaid $90 million in advances under the Credit Agreement. Additionally, we received $147.5 million in net proceeds and incurred $0.4 million in financing costs upon the issuance of the 8.25% Senior Notes. During the six months ended June 30, 2010, we paid $41.3 million in regular quarterly cash distributions to our general and limited partners, paid $54 million in excess of Holly’s transferred basis in the storage assets acquired in March 2010 and paid $2.3 million for the purchase of common units for recipients of our restricted unit incentive grants. For the six months ended June 30, 2009, we received $99 million and repaid $81 million in advances under the Credit Agreement. We also received $58.4 million in proceeds and incurred $0.2 million in costs with respect to our May 2009 equity offering. Additionally, for the six months ended June 30, 2009 we paid aggregate cash distributions to all HEP unitholders, including the general partner interest, of $28 million. We also received a $1.2 million capital contribution from our general partner and paid $0.6 million during the six months ended June 30, 2009 for the purchase of common units for recipients of restricted grants.

 

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Capital Requirements
Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements consist of maintenance capital expenditures and expansion capital expenditures. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.
Each year the Holly Logistics Services, L.L.C. (“HLS”) board of directors approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2010 capital budget is comprised of $5.3 million for maintenance capital expenditures and $6 million for expansion capital expenditures. In March 2010, the HLS board of directors approved our $93 million acquisition of the Tulsa east storage tank and loading rack assets and Lovington asphalt rack loading facility from Holly on March 31, 2010.
We are currently discussing a project with Holly in which we would build four to five interconnecting pipelines between Holly’s Tulsa east and west refining facilities. The project, which has not been finalized, would cost approximately $30 million to complete with construction expected to begin later this year.
We have an option agreement with Holly, granting us an option to purchase Holly’s 75% equity interests in the UNEV Pipeline, a joint venture pipeline currently under construction that will be capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada. Under this agreement, we have an option to purchase Holly’s equity interests in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Holly’s investment in the joint venture pipeline, plus interest at 7% per annum. The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The current total cost of the pipeline project including terminals is expected to be approximately $290 million. This includes a project scope change that includes the construction of ethanol blending and storage facilities at the Cedar City terminal. Holly has announced the commencement of the final construction phase of the pipeline and expects the pipeline to be mechanically complete in the second quarter of 2011.
We expect that our currently planned sustaining and maintenance capital expenditures as well as expenditures for acquisitions and capital development projects such as the UNEV Pipeline described above, will be funded with existing cash generated by operations, the sale of additional limited partner common units, the issuance of debt securities and advances under our $300 million Credit Agreement, or a combination thereof. We are not obligated to purchase the UNEV Pipeline nor are we subject to any fees or penalties if HLS’ board of directors decides not to proceed with this opportunity.
Credit Agreement
Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. Any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, are not significant.

 

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We may prepay all loans at any time without penalty, except for payment of certain breakage and related costs. We are required to reduce all working capital borrowings under the Credit Agreement to zero for a period of at least 15 consecutive days in each twelve-month period prior to the maturity date of the agreement. As of June 30, 2010, we had no working capital borrowings.
Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to 1.50%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the agreement). At June 30, 2010, we were subject to an applicable margin of 1.75%. We incur a commitment fee on the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At June 30, 2010, we are subject to a .30% commitment fee on the $145 million unused portion of the Credit Agreement. The agreement expires in August 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will become due and payable.
The Credit Agreement imposes certain requirements on us, including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies.
Additionally, the Credit Agreement contains certain provisions whereby the lenders may accelerate payment of outstanding debt under certain circumstances.
Senior Notes
The 6.25% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants, which we are subject to and currently in compliance with, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Senior Notes.
Indebtedness under the Senior Notes is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, are not significant.

 

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The carrying amounts of our long-term debt are as follows:
                 
    June 30,     December 31,  
    2010     2009  
    (In thousands)  
Credit Agreement
  $ 155,000     $ 206,000  
6.25% Senior Notes
               
Principal
    185,000       185,000  
Unamortized discount
    (1,774 )     (1,964 )
Unamortized premium — dedesignated fair value hedge
    1,617       1,791  
 
           
 
    184,843       184,827  
 
           
 
               
8.25% Senior Notes
               
Principal
    150,000        
Unamortized discount
    (2,364 )      
 
           
 
    147,636        
 
           
 
               
Total long-term debt
  $ 487,479     $ 390,827  
 
           
See “Risk Management” for a discussion of our interest rate swaps.
Contractual Obligations
During the six months ended June 30, 2010, we repaid net advances of $51 million resulting in $155 million of outstanding principal under the Credit Agreement at June 30, 2010.
In March 2010, we issued $150 million aggregate principal amount of 8.25% Senior Notes maturing March 15, 2018.
There were no other significant changes to our long-term contractual obligations during this period.
Impact of Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the six months ended June 30, 2010 and 2009.
A substantial majority of our revenues are generated under long-term contracts that provide for increases in our rates and minimum revenue guarantees annually for increases in the PPI. Historically, the PPI has increased an average of 3.1% annually over the past 5 calendar years. This is no indication of PPI increases to be realized in the future. Furthermore, certain of our long-term contracts have provisions that limit the level of annual PPI percentage rate increases.
Environmental Matters
Our operation of pipelines, terminals, and associated facilities in connection with the storage and transportation of refined products and crude oil is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent 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. 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 both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.

 

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Under the Omnibus Agreement, Holly agreed to indemnify us up to certain aggregate amounts for any environmental noncompliance and remediation liabilities associated with assets transferred to us and occurring or existing prior to the date of such transfers. The transfers that are covered by the agreement include the refined product pipelines, terminals and tanks transferred by Holly’s subsidiaries in connection with our initial public offering in July 2004, the intermediate pipelines acquired in July 2005, the crude pipelines and tankage assets acquired in 2008, and the asphalt loading rack facility acquired in March 2010. The Omnibus Agreement provides environmental indemnification of up to $15 million for the assets transferred to us, other than the crude pipelines and tankage assets, plus an additional $2.5 million for the intermediate pipelines acquired in July 2005. Except as described below, Holly’s indemnification obligations described above will remain in effect for an asset for ten years following the date it is transferred to us. The Omnibus Agreement also provides an additional $7.5 million of indemnification through 2023 for environmental noncompliance and remediation liabilities specific to the crude pipelines and tankage assets. Holly’s indemnification obligations described above do not apply to (i) the Tulsa west loading racks acquired in August 2009, (ii) the 16-inch intermediate pipeline acquired in June 2009, (iii) the Roadrunner Pipeline, (iv) the Beeson Pipeline, (v) the logistics and storage assets acquired from Sinclair in December 2009, or (vi) the Tulsa east storage tanks and loading racks acquired in March 2010.
Under provisions of the Holly ETA and Holly PTTA, Holly will indemnify us for environmental liabilities arising from our pre-ownership operations of the Tulsa west loading rack facilities acquired from Holly in August 2009, the Tulsa logistics and storage assets acquired from Sinclair in December 2009 and the Tulsa east storage tanks and loading racks acquired from Holly in March 2010. Additionally, Holly agreed to indemnify us for any liabilities arising from Holly’s operation of the loading racks under the Holly ETA.
We have an environmental agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Alon in 2005, under which Alon will indemnify us through 2015, subject to a $100,000 deductible and a $20 million maximum liability cap.
There are environmental remediation projects that are currently in progress that relate to certain assets acquired from Holly. Certain of these projects were underway prior to our purchase and represent liabilities of Holly Corporation as the obligation for future remediation activities was retained by Holly. As of June 30, 2010, we have an accrual of $0.4 million that relates to environmental clean-up projects. The remaining projects, including assessment and monitoring activities, are covered under the Holly environmental indemnification discussed above and represent liabilities of Holly Corporation.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows
Our significant accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Operations — Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2009. Certain critical accounting policies that materially affect the amounts recorded in our consolidated financial statements include revenue recognition, assessing the possible impairment of certain long-lived assets and assessing contingent liabilities for probable losses. There have been no changes to these policies in 2010. We consider these policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.

 

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RISK MANAGEMENT
We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.
As of June 30, 2010, we have an interest rate swap that hedges our exposure to the cash flow risk caused by the effects of LIBOR changes on a $155 million Credit Agreement advance. This interest rate swap effectively converts our $155 million LIBOR based debt to fixed rate debt having an interest rate of 3.74% plus an applicable margin, currently 1.75%, which equals an effective interest rate of 5.49% as of June 30, 2010. The maturity date of this swap contract is February 28, 2013.
We have designated this interest rate swap as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we have determined that this interest rate swap is effective in offsetting the variability in interest payments on our $155 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash flow hedge on a quarterly basis to its fair value with the offsetting fair value adjustment to accumulated other comprehensive income. Also on a quarterly basis, we measure hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of our swap against the expected future interest payments on our $155 million variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive income to interest expense. To date, we have had no ineffectiveness on our cash flow hedge.
Additional information on our interest rate swap as of June 30, 2010 is as follows:
                         
    Balance Sheet           Location of Offsetting   Offsetting  
Interest Rate Swap   Location   Fair Value     Balance   Amount  
    (In thousands)  
Liability
                       
Cash flow hedge — $155 million LIBOR based debt
  Other long-term liabilities   $ 11,122     Accumulated other comprehensive loss   $ 11,122  
 
                   
We review publicly available information on our counterparty in order to review and monitor its financial stability and assess its ongoing ability to honor its commitment under the interest rate swap contract. This counterparty is a large financial institution. Furthermore, we have not experienced, nor do we expect to experience, any difficulty in the counterparty honoring its commitment.
The market risk inherent in our debt positions is the potential change arising from increases or decreases in interest rates as discussed below.
At June 30, 2010, we had an outstanding principal balance on our 6.25% Senior Notes and 8.25% Senior Notes of $185 million and $150 million, respectively. A change in interest rates would generally affect the fair value of the Senior Notes, but not our earnings or cash flows. At June 30, 2010, the fair value of our 6.25% Senior Notes and 8.25% Senior Notes were $173.9 million and $148.5 million, respectively. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6.25% Senior Notes and 8.25% Senior Notes at June 30, 2010 would result in a change of approximately $5.3 million and $6.9 million, respectively, in the fair value of the underlying notes.
For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At June 30, 2010, outstanding principal under the Credit Agreement was $155 million. By means of our cash flow hedge, we have effectively converted the variable rate on $155 million of outstanding principal to a fixed rate of 5.49%.

 

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At June 30, 2010, our cash and cash equivalents included highly liquid investments with a maturity of six months or less at the time of purchase. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our investment portfolio.
Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.
We have a risk management oversight committee that is made up of members from our senior management. This committee monitors our risk environment and provides direction for activities to mitigate, to an acceptable level, identified risks that may adversely affect the achievement of our goals.

 

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Item 3. Quantitative and Qualitative Disclosures About Market Risks
Market risk is the risk of loss arising from adverse changes in market rates and prices. See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of market risk exposures that we have with respect to our cash and cash equivalents and long-term debt. We utilize derivative instruments to hedge our interest rate exposure, also discussed under “Risk Management.”
Since we do not own products shipped on our pipelines or terminalled at our terminal facilities, we do not have market risks associated with commodity prices.
Item 4. Controls and Procedures
(a) Evaluation of disclosure controls and procedures
Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2010.
(b) Changes in internal control over financial reporting
There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

 

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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.
Item 6. Exhibits
       
4.1 +  
Seventh Supplemental Indenture, dated as of April 14, 2010, among Holly Energy Storage- Tulsa LLC, Holly Energy Storage-Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association.
     
 
4.2 +  
Eighth Supplemental Indenture, dated as of June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association.
     
 
4.3 +  
First Supplemental Indenture, dated as of April 14, 2010, among Holly Energy Storage-Tulsa LLC, Holly Energy Storage-Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association.
     
 
4.4 +  
Second Supplemental Indenture, dated as of June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors, and U.S. Bank National Association.
     
 
10.1 +  
Amendment to First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated as of June 11, 2010, by and between Holly Refining & Marketing-Tulsa LLC, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC.
     
 
10.2 +*  
Form of Holly Logistic Services, L.L.C. Performance Unit Agreement.
     
 
12.1 +  
Computation of Ratio of Earnings to Fixed Charges.
     
 
31.1 +  
Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
     
 
31.2 +  
Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
     
 
32.1 ++  
Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
     
 
32.2 ++  
Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
     
+  
Filed herewith.
 
++  
Furnished herewith.
 
*  
Constitutes management contracts or compensatory plans or arrangements.

 

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HOLLY ENERGY PARTNERS, L.P.
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
 
  HOLLY ENERGY PARTNERS, L.P.    
 
  (Registrant)    
 
       
 
  By: HEP LOGISTICS HOLDINGS, L.P.    
 
  its General Partner    
 
       
 
  By: HOLLY LOGISTIC SERVICES, L.L.C.    
 
  its General Partner    
 
       
Date: July 30, 2010
  /s/ Bruce R. Shaw
 
Bruce R. Shaw
   
 
  Senior Vice President and    
 
  Chief Financial Officer    
 
  (Principal Financial Officer)    
 
       
 
  /s/ Scott C. Surplus
 
Scott C. Surplus
   
 
  Vice President and Controller    
 
  (Principal Accounting Officer)    

 

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