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 September 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 October 22, 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 12.1
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2

 

- 2 -


Table of Contents

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.

 

- 3 -


Table of Contents

Item 1. Financial Statements
Holly Energy Partners, L.P.
Consolidated Balance Sheets
                 
    September 30,        
    2010     December 31,  
    (Unaudited)     2009  
    (In thousands, except unit data)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 706     $ 2,508  
Accounts receivable:
               
Trade
    3,720       4,693  
Affiliates
    17,599       14,074  
 
           
 
    21,319       18,767  
 
               
Prepaid and other current assets
    1,121       739  
Current assets of discontinued operations
          2,195  
 
           
Total current assets
    23,146       24,209  
 
               
Properties and equipment, net
    424,806       398,044  
Transportation agreements, net
    110,226       115,436  
Goodwill
    49,109       49,109  
Investment in SLC Pipeline
    25,513       25,919  
Other assets
    1,784       4,128  
 
           
 
               
Total assets
  $ 634,584     $ 616,845  
 
           
 
               
LIABILITIES AND PARTNERS’ EQUITY
               
Current liabilities:
               
Accounts payable:
               
Trade
  $ 2,978     $ 3,860  
Affiliates
    2,808       2,351  
 
           
 
    5,786       6,211  
 
               
Accrued interest
    1,532       2,863  
Deferred revenue
    11,681       8,402  
Accrued property taxes
    1,497       1,072  
Other current liabilities
    1,042       1,257  
Credit agreement borrowings
    157,000        
 
           
Total current liabilities
    178,538       19,805  
 
               
Long-term debt
    332,564       390,827  
Other long-term liabilities
    12,534       12,349  
 
               
Partners’ equity:
               
Common unitholders (22,078,509 units and 21,141,009 units issued and outstanding at September 30, 2010 and December 31, 2009, respectively)
    266,957       275,553  
Class B subordinated unitholders (937,500 units issued and outstanding at December 31, 2009)
          21,426  
General partner interest (2% interest)
    (144,184 )     (93,974 )
Accumulated other comprehensive loss
    (11,825 )     (9,141 )
 
           
 
               
Total partners’ equity
    110,948       193,864  
 
           
 
               
Total liabilities and partners’ equity
  $ 634,584     $ 616,845  
 
           
See accompanying notes.

 

- 4 -


Table of Contents

Holly Energy Partners, L.P.
Consolidated Statements of Income
(Unaudited)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
    (In thousands, except per unit data)  
Revenues:
                               
Affiliates
  $ 37,312     $ 28,359     $ 107,988     $ 71,746  
Third parties
    9,237       12,446       24,740       36,390  
 
                       
 
    46,549       40,805       132,728       108,136  
 
                       
 
                               
Operating costs and expenses:
                               
Operations
    13,632       11,103       40,187       32,076  
Depreciation and amortization
    7,237       6,580       22,038       19,209  
General and administrative
    1,508       1,848       5,984       4,979  
 
                       
 
    22,377       19,531       68,209       56,264  
 
                       
 
                               
Operating income
    24,172       21,274       64,519       51,872  
 
                               
Other income (expense):
                               
Equity in earnings of SLC Pipeline
    570       711       1,595       1,309  
SLC Pipeline acquisition costs
                      (2,500 )
Interest income
    1       2       6       10  
Interest expense
    (8,417 )     (6,418 )     (25,510 )     (16,225 )
Other
    9             2       65  
 
                       
 
    (7,837 )     (5,705 )     (23,907 )     (17,341 )
 
                       
 
                               
Income from continuing operations before income taxes
    16,335       15,569       40,612       34,531  
 
                               
State income tax
    (76 )     (100 )     (216 )     (266 )
 
                       
 
                               
Income from continuing operations
    16,259       15,469       40,396       34,265  
 
                               
Income from discontinued operations, net of noncontrolling interest of $269 and $1,191, respectively
          1,070             4,105  
 
                       
 
                               
Net income
    16,259       16,539       40,396       38,370  
 
                               
Less general partner interest in net income, Including incentive distributions
    3,172       2,022       8,727       5,163  
 
                       
 
                               
Limited partners’ interest in net income
  $ 13,087     $ 14,517     $ 31,669     $ 33,207  
 
                       
 
                               
Limited partners’ per unit interest in earnings — basic and diluted:
                               
Income from continuing operations
  $ 0.59     $ 0.73     $ 1.43     $ 1.66  
Income from discontinued operations
          0.05             0.23  
 
                       
Net income
  $ 0.59     $ 0.78     $ 1.43     $ 1.89  
 
                       
 
                               
Weighted average limited partners’ units outstanding
    22,079       18,520       22,079       17,546  
 
                       
See accompanying notes.

 

- 5 -


Table of Contents

Holly Energy Partners, L.P.
Consolidated Statements of Cash Flows
(Unaudited)
                 
    Nine Months Ended  
    September 30,  
    2010     2009 (1)  
    (In thousands)  
Cash flows from operating activities
               
Net income
  $ 40,396     $ 38,370  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization
    22,038       19,929  
Equity in earnings of SLC Pipeline, net of distributions
    406       (1,309 )
Change in fair value — interest rate swaps
    1,464       300  
Noncontrolling interest in earnings of Rio Grande Pipeline Company
          1,191  
Amortization of restricted and performance units
    1,770       631  
(Increase) decrease in current assets:
               
Accounts receivable — trade
    973       117  
Accounts receivable — affiliates
    (3,525 )     (1,781 )
Prepaid and other current assets
    (382 )     (477 )
Current assets of discontinued operations
    2,195        
Increase (decrease) in current liabilities:
               
Accounts payable — trade
    (882 )     (2,815 )
Accounts payable — affiliates
    457       (237 )
Accrued interest
    (1,331 )     (1,929 )
Deferred revenue
    3,279       (8,076 )
Accrued property taxes
    425       341  
Other current liabilities
    (215 )     (137 )
Other, net
    (939 )     670  
 
           
Net cash provided by operating activities
    66,129       44,788  
 
               
Cash flows from investing activities
               
Additions to properties and equipment
    (8,054 )     (27,478 )
Acquisition of assets from Holly Corporation
    (35,526 )     (46,000 )
Investment in SLC Pipeline
          (25,500 )
 
           
Net cash used for investing activities
    (43,580 )     (98,978 )
 
               
Cash flows from financing activities
               
Borrowings under credit agreement
    52,000       197,000  
Repayments of credit agreement borrowings
    (101,000 )     (152,000 )
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
    (62,648 )     (44,393 )
Distributions to noncontrolling interest
          (600 )
Purchase price in excess of transferred basis in assets acquired from Holly Corporation
    (57,474 )     (5,700 )
Purchase of units for restricted grants
    (2,276 )     (616 )
Deferred financing costs
    (493 )      
Cost of issuing common units
          (266 )
 
           
Net cash provided by (used for) financing activities
    (24,351 )     52,971  
 
               
Cash and cash equivalents
               
Increase (decrease) for the period
    (1,802 )     (1,219 )
Beginning of period
    2,508       5,269  
 
           
 
               
End of period
  $ 706     $ 4,050  
 
           
     
(1)  
Includes cash flows attributable to discontinued operations.
See accompanying notes.

 

- 6 -


Table of Contents

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 HEP unitholders
    (60,302 )     (1,519 )     (827 )           (62,648 )
Purchase price in excess of transferred basis in assets acquired from Holly Corporation
                (57,474 )           (57,474 )
Purchase of units for restricted grants
    (2,276 )                       (2,276 )
Amortization of restricted and performance units
    1,770                         1,770  
Comprehensive income:
                                       
Net income
    31,624       681       8,091             40,396  
Other comprehensive loss
                      (2,684 )     (2,684 )
 
                             
Comprehensive income
    31,624       681       8,091       (2,684 )     37,712  
 
                             
 
                                       
Balance September 30, 2010
  $ 266,957     $     $ (144,184 )   $ (11,825 )   $ 110,948  
 
                             
See accompanying notes.

 

- 7 -


Table of Contents

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 nine months ended September 30, 2009, net cash flows from our discontinued Rio Grande operations were $5.7 million.

 

- 8 -


Table of Contents

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 acquisitions from Holly, we recorded total property and equipment at Holly’s cost basis of $35.5 million and the purchase price in excess of Holly’s basis in the assets of $57.5 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.

 

- 9 -


Table of Contents

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 $157 million carrying amount of outstanding debt under our Credit Agreement at September 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 $183.2 million and $156.8 million, respectively, at September 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 September 30, 2010 represented a liability having a fair value of $11.8 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.

 

- 10 -


Table of Contents

Note 5: Properties and Equipment
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
 
               
Pipelines and terminals (1)
  $ 493,182     $ 455,075  
Land and right of way
    25,257       25,230  
Other
    13,926       12,528  
Construction in progress
    14,417       10,484  
 
           
 
    546,782       503,317  
Less accumulated depreciation
    121,976       105,273  
 
           
 
  $ 424,806     $ 398,044  
 
           
     
(1)  
We periodically evaluate estimated useful lives of our properties and equipment. Effective January 1, 2010, we revised the estimated useful lives of our terminal assets to 16 to 25 years. This change in estimated useful lives resulted in a $2.2 million reduction in depreciation expense for the nine months ended September 30, 2010.
We capitalized $0.4 million and $0.9 million in interest related to major construction projects during the nine months ended September 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 acquired in 2005 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:
                 
    September 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
    23,938       18,728  
 
           
 
  $ 110,226     $ 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.

 

- 11 -


Table of Contents

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 $0.8 million for the three months ended September 30, 2010 and 2009 and $2.1 million and $2 million for the nine months ended September 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 September 30, 2010, we have two types of equity-based compensation, which are described below. The compensation cost charged against income for these plans was $0.4 million and $0.2 million for the three months ended September 30, 2010 and 2009, respectively, and $1.8 million and $1.1 million for the nine months ended September 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 September 30, 2010, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 169,939 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 nine months ended September 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
    36,755       43.13                  
Vesting and transfer of full ownership to recipients
    (41,505 )     38.53                  
Forfeited
    (1,226 )     34.28                  
 
                             
Outstanding at September 30, 2010 (nonvested)
    47,295     $ 37.47       0.9 year     $ 2,424  
 
                       
The fair value of restricted units that were vested and transferred to recipients during the nine months ended September 30, 2010 and 2009 were $1.6 million and $1.2 million, respectively. As of September 30, 2010, there was $0.7 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 nine months ended September 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.

 

- 12 -


Table of Contents

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 September 30, 2010, estimated share payouts for outstanding nonvested performance unit awards ranged from 110% to 120%.
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 nine months ended September 30, 2010 is presented below:
         
    Payable  
Performance Units   In Units  
 
       
Outstanding at January 1, 2010 (nonvested)
    54,771  
Granted
    16,965  
Vesting and transfer of common units to recipients
    (11,785 )
Forfeited
    (536 )
 
     
Outstanding at September 30, 2010 (nonvested)
    59,415  
 
     
The fair value of performance units vested and transferred to recipients during the nine months ended September 30, 2010 and 2009 was $0.5 million and $0.4 million, respectively. Based on the weighted average fair value at September 30, 2010 of $32.97, there was $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 1.3 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 nine months ended September 30, 2010, we received advances totaling $52 million and repaid $101 million, resulting in the net repayment of $49 million in advances. As of September 30, 2010, we had $157 million outstanding under the Credit Agreement that was used to finance acquisitions and capital projects. The Credit Agreement expires in August 2011; therefore, outstanding borrowings, all of which were previously classified as long-term liabilities, are currently classified as current liabilities. We intend to renew the credit agreement prior to expiration and to continue to finance outstanding credit agreement borrowings. Upon renewal of the Credit Agreement, outstanding borrowings not designated for working capital purposes will be reclassified as long-term debt.
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.

 

- 13 -


Table of Contents

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 September 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 September 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 September 30, 2010, we are subject to a .30% commitment fee on the $143 million unused portion of the Credit Agreement.
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 have 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.

 

- 14 -


Table of Contents

The carrying amounts of our debt are as follows:
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
Credit Agreement
  $ 157,000     $ 206,000  
 
               
6.25% Senior Notes
               
Principal
    185,000       185,000  
Unamortized discount
    (1,679 )     (1,964 )
Unamortized premium — dedesignated fair value hedge
    1,531       1,791  
 
           
 
    184,852       184,827  
 
           
 
               
8.25% Senior Notes
               
Principal
    150,000        
Unamortized discount
    (2,288 )      
 
           
 
    147,712        
 
           
 
               
Total debt
    489,564       390,827  
 
               
Less credit agreement borrowings classified as current liabilities
    157,000        
 
           
Total long-term debt
  $ 332,564     $ 390,827  
 
           
Interest Rate Risk Management
We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.
As of September 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 September 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 loss. 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 loss to interest expense. To date, we have had no ineffectiveness on our cash flow hedge.
Additional information on our interest rate swap as of September 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   $ 11,825     Accumulated other comprehensive loss   $ 11,825  
 
                           
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.

 

- 15 -


Table of Contents

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 nine months ended September 30, 2010 and 2009, we recognized $1.5 million and $0.3 million in non-cash charges to interest expense as a result of fair value adjustments to our interest rate swaps.
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 $1.5 million at September 30, 2010, is being amortized as a reduction to interest expense over the remaining term of the 6.25% Senior Notes.
Interest Expense and Other Debt Information
Interest expense consists of the following components:
                 
    September 30,     September 30,  
    2010     2009  
    (In thousands)  
Interest on outstanding debt:
               
Credit Agreement, net of interest on interest rate swap
  $ 6,908     $ 7,745  
6.25% Senior Notes, net of interest on interest rate swaps
    8,514       8,320  
8.25% Senior Notes
    6,940        
Partial settlement of interest rate swap — cash flow hedge
    1,076        
Net fair value adjustments to interest rate swaps
    1,464       300  
Net amortization of discount and deferred debt issuance costs
    710       529  
Commitment fees
    286       202  
 
           
Total interest incurred
    25,898       17,096  
 
               
Less capitalized interest
    388       871  
 
           
 
               
Net interest expense
  $ 25,510     $ 16,225  
 
           
 
               
Cash paid for interest (1)
  $ 29,515     $ 18,307  
 
           
     
(1)  
Net of cash received under our interest rate swap agreements of $1.9 million for the nine months ended September 30, 2010 and $3.8 million for the nine months ended September 30, 2009.
Note 9: Significant Customers
All revenues are domestic revenues, of which 95 percent are currently generated from our two largest customers: Holly and Alon. The major part of our 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     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
Holly
    80 %     70 %     81 %     66 %
Alon
    15 %     26 %     14 %     29 %

 

- 16 -


Table of Contents

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 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 assets acquired from Holly in 2005 and 2009);
   
Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to assets acquired from Holly in 2008);
   
Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east 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 facilities acquired from Holly in 2009);
   
Holly NPA (natural gas pipeline throughput agreement expiring in 2024); and
   
Holly ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to the Lovington 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, which was insignificant, these agreements with Holly will result in minimum annualized payments to us of $133 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.

 

- 17 -


Table of Contents

Related party transactions with Holly are as follows:
 
Revenues received from Holly were $37.3 million and $28.4 million for the three months ended September 30, 2010 and 2009, respectively, and $108 million and $71.7 million for the nine months ended September 30, 2010 and 2009, respectively.
 
Holly charged general and administrative services under the Omnibus Agreement of $0.6 million for the three months ended September 30, 2010 and 2009 and $1.7 million for the nine months ended September 30, 2010 and 2009.
 
We reimbursed Holly for costs of employees supporting our operations of $4.8 million and $4.2 million for the three months ended September 30, 2010 and 2009, respectively, and $13.6 million and $12.8 million for the nine months ended September 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.
 
We distributed $9.1 million and $7.6 million for the three months ended September 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 $26.5 million and $21.6 million during the nine months ended September 30, 2010 and 2009, respectively.
 
Accounts receivable from Holly were $17.6 million and $14.1 million at September 30, 2010 and December 31, 2009, respectively.
 
Accounts payable to Holly were $2.8 million and $2.4 million at September 30, 2010 and December 31, 2009, respectively.
 
Revenues for the three and the nine months ended September 30, 2010 include $0.6 million and $2.9 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 September 30, 2010 and December 31, 2009, includes $3.4 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 $3.4 million deferred at September 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 $5.4 million and $8.8 million for the three months ended September 30, 2010 and 2009, respectively, and $13.8 million and $25.8 million for the nine months ended September 30, 2010 and 2009, respectively under the Alon PTA. Additionally, revenues received under a pipeline capacity lease agreement with Alon were $1.7 million and $1.6 million for the three months ended September 30, 2010 and 2009, respectively, and $4.9 million and $5 million for the nine months ended September 30, 2010 and 2009, respectively.
 
Accounts receivable — trade include receivable balances from Alon of $3.6 million at September 30, 2010 and $4 million at December 31, 2009.

 

- 18 -


Table of Contents

 
Revenues for the three and the nine months ended September 30, 2010 include $1.1 million and $2.9 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 September 30, 2010 and December 31, 2009 includes $8.3 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 $8.3 million deferred at September 30, 2010.
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 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     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
    (In thousands)  
 
                               
General partner interest in net income
  $ 271     $ 300     $ 659     $ 691  
General partner incentive distribution
    2,901       1,722       8,068       4,472  
 
                       
Total general partner interest in net income attributable to HEP
  $ 3,172     $ 2,022     $ 8,727     $ 5,163  
 
                       

 

- 19 -


Table of Contents

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 October 26, 2010, we announced our cash distribution for the third quarter of 2010 of $0.835 per unit. The distribution is payable on all common, subordinated, and general partner units and will be paid November 12, 2010 to all unitholders of record on November 5, 2010.
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     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
    (In thousands, except per unit data)  
 
                               
General partner interest
  $ 436     $ 336     $ 1,280     $ 947  
General partner incentive distribution
    2,901       1,722       8,068       4,472  
 
                       
Total general partner distribution
    3,337       2,058       9,348       5,419  
Limited partner distribution
    18,435       14,723       54,566       41,938  
 
                       
Total regular quarterly cash distribution
  $ 21,772     $ 16,781     $ 63,914     $ 47,357  
 
                       
Cash distribution per unit applicable to limited partners
  $ 0.835     $ 0.795     $ 2.475     $ 2.355  
 
                       
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 contributed and acquired from Holly while under common control of Holly had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $217.9 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 (Loss)
We have other comprehensive income (loss) resulting from fair value adjustments to our cash flow hedge. Our comprehensive income is as follows:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
    (In thousands)  
 
                               
Net income
  $ 16,259     $ 16,808     $ 40,396     $ 39,561  
Other comprehensive income (loss):
                               
Change in fair value of cash flow hedge
    (703 )     (1,482 )     (3,760 )     2,786  
Reclassification adjustment to net income on partial settlement of cash flow hedge
                1,076        
 
                       
Other comprehensive income (loss)
    (703 )     (1,482 )     (2,684 )     2,786  
 
                       
Comprehensive income
    15,556       15,326       37,712       42,347  
Less noncontrolling interest in comprehensive income
          269             1,191  
 
                       
Comprehensive income attributable to HEP unitholders
  $ 15,556     $ 15,057     $ 37,712     $ 41,156  
 
                       

 

- 20 -


Table of Contents

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.

 

- 21 -


Table of Contents

Condensed Consolidating Balance Sheet
                                 
            Guarantor              
September 30, 2010   Parent     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
ASSETS
                               
Current assets:
                               
Cash and cash equivalents
  $ 2     $ 704     $     $ 706  
Accounts receivable
          21,319             21,319  
Intercompany accounts receivable (payable)
    (73,158 )     73,158              
Prepaid and other current assets
    368       753             1,121  
 
                       
Total current assets
    (72,788 )     95,934             23,146  
 
                               
Properties and equipment, net
          424,806             424,806  
Investment in subsidiaries
    517,300             (517,300 )      
Transportation agreements, net
          110,226             110,226  
Goodwill
          49,109             49,109  
Investment in SLC Pipeline
          25,513             25,513  
Other assets
    1,314       470             1,784  
 
                       
Total assets
  $ 445,826     $ 706,058     $ (517,300 )   $ 634,584  
 
                       
 
                               
LIABILITIES AND PARTNERS’ EQUITY
                               
Current liabilities:
                               
Accounts payable
  $     $ 5,786     $     $ 5,786  
Accrued interest
    1,514       18             1,532  
Deferred revenue
          11,681             11,681  
Accrued property taxes
          1,497             1,497  
Other current liabilities
    800       242             1,042  
Credit agreement borrowings
          157,000             157,000  
 
                       
Total current liabilities
    2,314       176,224             178,538  
 
                               
Long-term debt
    332,564                   332,564  
Other long-term liabilities
          12,534             12,534  
Partners’ equity
    110,948       517,300       (517,300 )     110,948  
 
                       
Total liabilities and partners’ equity
  $ 445,826     $ 706,058     $ (517,300 )   $ 634,584  
 
                       
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  
 
                       

 

- 22 -


Table of Contents

Condensed Consolidating Statement of Income
                                 
            Guarantor              
Three months ended September 30, 2010   Parent     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                               
Affiliates
  $     $ 37,312     $     $ 37,312  
Third parties
          9,237             9,237  
 
                       
 
          46,549             46,549  
 
                               
Operating costs and expenses:
                               
Operations
          13,632             13,632  
Depreciation and amortization
          7,237             7,237  
General and administrative
    888       620             1,508  
 
                       
 
    888       21,489             22,377  
 
                       
Operating income (loss)
    (888 )     25,060             24,172  
 
                               
Equity in earnings of subsidiaries
    23,285             (23,285 )      
Equity in earnings of SLC Pipeline
          570             570  
Interest income (expense)
    (6,138 )     (2,278 )           (8,416 )
Other
          9             9  
 
                       
 
    17,147       (1,699 )     (23,285 )     (7,837 )
 
                       
Income (loss) before income taxes
    16,259       23,361       (23,285 )     16,335  
 
                               
State income tax
          (76 )           (76 )
 
                       
 
                               
Net income
  $ 16,259     $ 23,285     $ (23,285 )   $ 16,259  
 
                       
Condensed Consolidating Statement of Income
                                         
            Guarantor     Non-              
Three months ended September 30, 2009   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                                       
Affiliates
  $     $ 28,359     $     $     $ 28,359  
Third parties
          12,446                   12,446  
 
                             
 
          40,805                   40,805  
 
                                       
Operating costs and expenses:
                                       
Operations
          11,103                   11,103  
Depreciation and amortization
          6,580                   6,580  
General and administrative
    1,210       638                   1,848  
 
                             
 
    1,210       18,321                   19,531  
 
                             
Operating income (loss)
    (1,210 )     22,484                   21,274  
 
                                       
Equity in earnings of subsidiaries
    21,408       628             (22,036 )      
Equity in earnings of SLC Pipeline
          711                   711  
Interest income (expense)
    (3,659 )     (2,757 )                 (6,416 )
Other
                             
 
                             
 
    17,749       (1,418 )           (22,036 )     (5,705 )
 
                             
Income (loss) from continuing operations before income taxes
    16,539       21,066             (22,036 )     15,569  
 
                                       
State income tax
          (100 )                 (100 )
 
                             
 
                                       
Income from continuing operations
    16,539       20,966             (22,036 )     15,469  
 
                                       
Income from discontinued operations
          442       897       (269 )     1,070  
 
                             
 
                                       
Net income
  $ 16,539     $ 21,408     $ 897     $ (22,305 )   $ 16,539  
 
                             

 

- 23 -


Table of Contents

Condensed Consolidating Statement of Income
                                 
            Guarantor              
Nine months ended September 30, 2010   Parent     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                               
Affiliates
  $     $ 107,988     $     $ 107,988  
Third parties
          24,740             24,740  
 
                       
 
          132,728             132,728  
 
                               
Operating costs and expenses:
                               
Operations
          40,187             40,187  
Depreciation and amortization
          22,038             22,038  
General and administrative
    3,970       2,014             5,984  
 
                       
 
    3,970       64,239             68,209  
 
                       
Operating income (loss)
    (3,970 )     68,489             64,519  
 
                               
Equity in earnings of subsidiaries
    61,603             (61,603 )      
Equity in earnings of SLC Pipeline
          1,595             1,595  
Interest income (expense)
    (17,237 )     (8,267 )           (25,504 )
Other
          2             2  
 
                       
 
    44,366       (6,670 )     (61,603 )     (23,907 )
 
                       
Income (loss) before income taxes
    40,396       61,819       (61,603 )     40,612  
 
                               
State income tax
          (216 )           (216 )
 
                       
 
                               
Net income
  $ 40,396     $ 61,603     $ (61,603 )   $ 40,396  
 
                       
Condensed Consolidating Statement of Income
                                         
            Guarantor     Non-              
Nine months ended September 30, 2009   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
Revenues:
                                       
Affiliates
  $     $ 71,746     $     $     $ 71,746  
Third parties
          36,390                   36,390  
 
                             
 
          108,136                   108,136  
 
                                       
Operating costs and expenses:
                                       
Operations
          32,076                   32,076  
Depreciation and amortization
          19,209                   19,209  
General and administrative
    3,195       1,784                   4,979  
 
                             
 
    3,195       53,069                   56,264  
 
                             
Operating income (loss)
    (3,195 )     55,067                   51,872  
 
                                       
Equity in earnings of subsidiaries
    50,026       2,780             (52,806 )      
Equity in earnings of SLC Pipeline
          1,309                   1,309  
SLC Pipeline acquisition costs
          (2,500 )                 (2,500 )
Interest income (expense)
    (8,461 )     (7,754 )                 (16,215 )
Other
          65                   65  
 
                             
 
    41,565       (6,100 )           (52,806 )     (17,341 )
 
                             
Income (loss) from continuing operations before income taxes
    38,370       48,967             (52,806 )     34,531  
 
                                       
State income tax
          (266 )                 (266 )
 
                             
 
                                       
Income from continuing operations
    38,370       48,701             (52,806 )     34,265  
 
                                       
Income from discontinued operations
          1,325       3,971       (1,191 )     4,105  
 
                             
 
                                       
Net income
  $ 38,370     $ 50,026     $ 3,971     $ (53,997 )   $ 38,370  
 
                             

 

- 24 -


Table of Contents

Condensed Consolidating Statement of Cash Flows
                                 
            Guarantor              
Nine months ended September 30, 2010   Parent     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
 
                               
Cash flows from operating activities
  $ (82,123 )   $ 148,252     $     $ 66,129  
 
                               
Cash flows from investing activities
                               
Additions to properties and equipment
          (8,054 )           (8,054 )
Acquisition of assets from Holly Corporation
          (35,526 )           (35,526 )
 
                       
 
          (43,580 )           (43,580 )
 
                       
Cash flows from financing activities
                               
Net repayments under credit agreement
          (49,000 )           (49,000 )
Net proceeds from issuance of senior notes
    147,540                   147,540  
Distributions to HEP unitholders
    (62,648 )                 (62,648 )
Purchase price in excess of transferred basis in assets acquired from Holly Corporation
          (57,474 )           (57,474 )
Purchase of units for restricted grants
    (2,276 )                 (2,276 )
Deferred financing costs
    (493 )                 (493 )
 
                       
 
    82,123       (106,474 )           (24,351 )
 
                       
 
                               
Cash and cash equivalents
                               
Increase (decrease) for the period
          (1,802 )           (1,802 )
Beginning of period
    2       2,506             2,508  
 
                       
 
                               
End of period
  $ 2     $ 704     $     $ 706  
 
                       
Condensed Consolidating Statement of Cash Flows
                                         
            Guarantor     Non-              
Nine months ended September 30, 2009   Parent     Subsidiaries     Guarantor     Eliminations     Consolidated  
    (In thousands)  
 
                                       
Cash flows from operating activities
  $ (14,887 )   $ 56,819     $ 4,256     $ (1,400 )   $ 44,788  
 
                                       
Cash flows from investing activities
                                       
Additions to properties and equipment
          (27,406 )     (72 )           (27,478 )
Acquisition of assets from Holly Corporation
          (46,000 )                 (46,000 )
Investment in SLC Pipeline
          (25,500 )                 (25,500 )
 
                             
 
          (98,906 )     (72 )           (98,978 )
 
                             
Cash flows from financing activities
                                       
Net borrowings under credit agreement
          45,000                   45,000  
Proceeds from issuance of common units
    58,355                         58,355  
Contribution from general partner
    1,191                         1,191  
Distributions to HEP unitholders
    (44,393 )           (2,000 )     2,000       (44,393 )
Distributions to noncontrolling interest
                      (600 )     (600 )
Purchase price in excess of transferred basis in assets acquired from Holly Corporation
          (5,700 )                 (5,700 )
Purchase of units for restricted grants
          (616 )                 (616 )
Cost of issuing common units
    (266 )                       (266 )
 
                             
 
    14,887       38,684       (2,000 )     1,400       52,971  
 
                             
 
                                       
Cash and cash equivalents
                                       
Increase (decrease) for the period
          (3,403 )     2,184             (1,219 )
Beginning of period
    2       3,706       1,561             5,269  
 
                             
 
                                       
End of period
  $ 2     $ 303     $ 3,745     $     $ 4,050  
 
                             

 

- 25 -


Table of Contents

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.

 

- 26 -


Table of Contents

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 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 assets acquired from Holly in 2005 and 2009);
   
Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to assets acquired from Holly in 2008);
   
Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024 that relates to the Tulsa east 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 facilities acquired from Holly in 2009);
   
Holly NPA (natural gas pipeline throughput agreement expiring in 2024); and
   
Holly ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to the Lovington 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.

 

- 27 -


Table of Contents

At October 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
Holly NPA
    0.6       2024     Minimum revenue commitment
Alon PTA
    22.7       2020     Minimum volume commitment
Alon capacity lease
    6.4       Various     Capacity lease
 
                 
 
                   
Total
  $ 162.1              
 
                 
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.

 

- 28 -


Table of Contents

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 nine months ended September 30, 2010 and 2009.
                         
    Three Months Ended     Change  
    September 30,     from  
    2010     2009     2009  
    (In thousands, except per unit data)  
Revenues
                       
Pipelines:
                       
Affiliates — refined product pipelines
  $ 12,340     $ 12,267     $ 73  
Affiliates — intermediate pipelines
    4,917       5,370       (453 )
Affiliates — crude pipelines
    9,775       7,563       2,212  
 
                 
 
    27,032       25,200       1,832  
Third parties — refined product pipelines
    7,277       10,552       (3,275 )
 
                 
 
    34,309       35,752       (1,443 )
Terminals and loading racks:
                       
Affiliates
    10,281       3,159       7,122  
Third parties
    1,959       1,894       65  
 
                 
 
    12,240       5,053       7,187  
 
                 
Total revenues
    46,549       40,805       5,744  
 
                       
Operating costs and expenses
                       
Operations
    13,632       11,103       2,529  
Depreciation and amortization
    7,237       6,580       657  
General and administrative
    1,508       1,848       (340 )
 
                 
 
    22,377       19,531       2,846  
 
                 
 
                       
Operating income
    24,172       21,274       2,898  
 
                       
Equity in earnings of SLC Pipeline
    570       711       (141 )
Interest income
    1       2       (1 )
Interest expense, including amortization
    (8,417 )     (6,418 )     (1,999 )
Other
    9             9  
 
                 
 
    (7,837 )     (5,705 )     (2,132 )
 
                 
 
                       
Income from continuing operations before income taxes
    16,335       15,569       766  
 
                       
State income tax
    (76 )     (100 )     24  
 
                 
 
                       
Income from continuing operations
    16,259       15,469       790  
 
                       
Income from discontinued operations, net of noncontrolling interest of $269 (1)
          1,070       (1,070 )
 
                 
 
                       
Net income
    16,259       16,539       (280 )
 
                       
Less general partner interest in net income, including incentive distributions (2)
    3,172       2,022       1,150  
 
                 
Limited partners’ interest in net income
  $ 13,087     $ 14,517     $ (1,430 )
 
                 
Limited partners’ earnings per unit — basic and diluted (2)
                       
Income from continuing operations
  $ 0.59     $ 0.73     $ (0.14 )
Income from discontinued operations
          0.05       (0.05 )
 
                 
Net income
  $ 0.59     $ 0.78     $ (0.19 )
 
                 
 
                       
Weighted average limited partners’ units outstanding
    22,079       18,520       3,559  
 
                 
EBITDA (3)
  $ 31,988     $ 29,888     $ 2,100  
 
                 
Distributable cash flow (4)
  $ 23,969     $ 20,678     $ 3,291  
 
                 
 
                       
Volumes from continuing operations (bpd) (1)
                       
Pipelines:
                       
Affiliates — refined product pipelines
    93,194       98,987       (5,793 )
Affiliates — intermediate pipelines
    83,227       88,053       (4,826 )
Affiliates — crude pipelines
    143,617       143,902       (285 )
 
                 
 
    320,038       330,942       (10,904 )
Third parties — refined product pipelines
    41,967       43,858       (1,891 )
 
                 
 
    362,005       374,800       (12,795 )
Terminals and loading racks:
                       
Affiliates
    183,312       122,413       60,899  
Third parties
    43,633       44,459       (826 )
 
                 
 
    226,945       166,872       60,073  
 
                 
Total for pipelines and terminal assets (bpd)
    588,950       541,672       47,278  
 
                 

 

- 29 -


Table of Contents

                         
    Nine Months Ended     Change  
    September 30,     from  
    2010     2009     2009  
    (In thousands, except per unit data)  
Revenues
                       
Pipelines:
                       
Affiliates — refined product pipelines
  $ 35,887     $ 31,186     $ 4,701  
Affiliates — intermediate pipelines
    15,673       11,438       4,235  
Affiliates — crude pipelines
    28,907       21,215       7,692  
 
                 
 
    80,467       63,839       16,628  
Third parties — refined product pipelines
    19,136       31,125       (11,989 )
 
                 
 
    99,603       94,964       4,639  
Terminals and loading racks:
                       
Affiliates
    27,522       7,907       19,615  
Third parties
    5,603       5,265       338  
 
                 
 
    33,125       13,172       19,953  
 
                 
Total revenues
    132,728       108,136       24,592  
 
                       
Operating costs and expenses
                       
Operations
    40,187       32,076       8,111  
Depreciation and amortization
    22,038       19,209       2,829  
General and administrative
    5,984       4,979       1,005  
 
                 
 
    68,209       56,264       11,945  
 
                 
 
                       
Operating income
    64,519       51,872       12,647  
 
                       
Equity in earnings of SLC Pipeline
    1,595       1,309       286  
SLC Pipeline acquisition costs
          (2,500 )     2,500  
Interest income
    6       10       (4 )
Interest expense, including amortization
    (25,510 )     (16,225 )     (9,285 )
Other
    2       65       (63 )
 
                 
 
    (23,907 )     (17,341 )     (6,566 )
 
                 
 
                       
Income from continuing operations before income taxes
    40,612       34,531       6,081  
 
                       
State income tax
    (216 )     (266 )     50  
 
                 
 
                       
Income from continuing operations
    40,396       34,265       6,131  
 
                       
Income from discontinued operations, net of noncontrolling interest of $1,191 (1)
          4,105       (4,105 )
 
                 
 
                       
Net income
    40,396       38,370       2,026  
 
                       
Less general partner interest in net income, including incentive distributions (2)
    8,727       5,163       3,564  
 
                 
Limited partners’ interest in net income
  $ 31,669     $ 33,207     $ (1,538 )
 
                 
Limited partners’ earnings per unit — basic and diluted (2)
                       
Income from continuing operations
  $ 1.43     $ 1.66     $ (0.23 )
Income from discontinued operations
          0.23       (0.23 )
 
                 
Net income
  $ 1.43     $ 1.89     $ (0.46 )
 
                 
 
                       
Weighted average limited partners’ units outstanding
    22,079       17,546       4,533  
 
                 
EBITDA (3)
  $ 88,154     $ 74,831     $ 13,323  
 
                 
Distributable cash flow (4)
  $ 66,800     $ 51,677     $ 15,123  
 
                 
 
                       
Volumes from continuing operations (bpd) (1)
                       
Pipelines:
                       
Affiliates — refined product pipelines
    95,013       85,489       9,524  
Affiliates — intermediate pipelines
    82,844       64,494       18,350  
Affiliates — crude pipelines
    139,955       136,315       3,640  
 
                 
 
    317,812       286,298       31,514  
Third parties — refined product pipelines
    35,923       45,647       (9,724 )
 
                 
 
    353,735       331,945       21,790  
Terminals and loading racks:
                       
Affiliates
    177,946       106,969       70,977  
Third parties
    38,825       42,873       (4,048 )
 
                 
 
    216,771       149,842       66,929  
 
                 
Total for pipelines and terminal assets (bpd)
    570,506       481,787       88,719  
 
                 

 

- 30 -


Table of Contents

     
(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.
 
(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     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
    (In thousands)  
 
                               
Income from continuing operations
  $ 16,259     $ 15,469     $ 40,396     $ 34,265  
 
                               
Add (subtract):
                               
Interest expense
    8,135       5,314       22,230       15,396  
Amortization of discount and deferred debt issuance costs
    282       176       740       529  
Increase in interest expense — change in fair value of interest rate swaps and swap settlement costs
          928       2,540       300  
Interest income
    (1 )     (2 )     (6 )     (10 )
State income tax
    76       100       216       266  
Depreciation and amortization
    7,237       6,580       22,038       19,209  
EBITDA from discontinued operations
          1,323             4,876  
 
                       
 
                               
EBITDA
  $ 31,988     $ 29,888     $ 88,154     $ 74,831  
 
                       
     
(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 for 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.

 

- 31 -


Table of Contents

Set forth below is our calculation of distributable cash flow.
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
    (In thousands)  
 
                               
Income from continuing operations
  $ 16,259     $ 15,469     $ 40,396     $ 34,265  
 
                               
Add (subtract):
                               
Depreciation and amortization
    7,237       6,580       22,038       19,209  
Amortization of discount and deferred debt issuance costs
    282       176       740       529  
Increase in interest expense — change in fair value of interest rate swaps and swap settlement costs
          928       2,540       300  
Equity in excess cash flows over earnings of SLC Pipeline
    173       167       525       387  
Increase (decrease) in deferred revenue
    758       (3,407 )     3,279       (8,076 )
SLC Pipeline acquisition costs*
                      2,500  
Maintenance capital expenditures**
    (740 )     (545 )     (2,718 )     (2,262 )
Distributable cash flow from discontinued operations
          1,310             4,825  
 
                       
 
                               
Distributable cash flow
  $ 23,969     $ 20,678     $ 66,800     $ 51,677  
 
                       
     
*  
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.
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
Balance Sheet Data
               
       
Cash and cash equivalents
  $ 706     $ 2,508  
Working capital (5)
  $ (155,392 )   $ 4,404  
Total assets
  $ 634,584     $ 616,845  
Long-term debt (6)
  $ 332,564     $ 390,827  
Partners’ equity (7)
  $ 110,948     $ 193,864  
     
(5)  
Our credit agreement expires in August 2011; therefore, working capital at September 30, 2010 reflects $157 million of credit agreement borrowings that are currently classified as current liabilities. We intend to renew the credit agreement prior to expiration and to continue to finance outstanding credit agreement borrowings. Upon renewal, outstanding borrowings not designated for working capital purposes will be reclassified as long-term debt. Excluding the $157 million credit agreement borrowings, working capital was $1.6 million at September 30, 2010.
 
(6)  
Includes $206 million of credit agreement advances at December 31, 2009.
 
(7)  
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 contributed and acquired from Holly while under common control of Holly had been acquired from third parties, our acquisition cost in excess of Holly’s basis in the transferred assets of $217.9 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.

 

- 32 -


Table of Contents

Results of Operations — Three Months Ended September 30, 2010 Compared with Three Months Ended September 30, 2009
Summary
Income from continuing operations for the three months ended September 30, 2010 was $16.3 million, a $0.8 million increase compared to the three months ended September 30, 2009. This increase in overall earnings is due principally to earnings attributable to our December 2009 and March 2010 asset acquisitions, partially offset by a decrease in previously deferred revenue realized, decreased shipments and increased interest costs.
Revenues for the three months ended September 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 $2.4 million relating to deficiency payments associated with certain guaranteed shipping contracts were deferred during the three months ended September 30, 2010. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels or in 2011 when shipping rights expire unused after a twelve-month period.
Revenues
Total revenues from continuing operations for the three months ended September 30, 2010 were $46.5 million, a $5.7 million increase compared to the three months ended September 30, 2009. This is due principally to revenues attributable to our December 2009 and March 2010 asset acquisitions, partially offset by a $3.4 million decrease in previously deferred revenue realized and a decrease in pipeline shipments. The small decrease in affiliate pipeline shipments reflects slightly lower run rates at Holly’s Navajo refinery during the third quarter due to the impact of unscheduled downtime of certain operating units.
Revenues from our refined product pipelines were $19.6 million, a decrease of $3.2 million compared to the three months ended September 30, 2009. This decrease is due principally to a $3.2 million decrease in previously deferred revenue realized. Volumes shipped on our refined product pipelines averaged 135.2 thousand barrels per day (“mbpd”) compared to 142.8 mbpd for the same period last year.
Revenues from our intermediate pipelines were $4.9 million, a decrease of $0.5 million compared to the three months ended September 30, 2009. This includes a $0.2 million decrease in previously deferred revenue realized. Shipments on our intermediate product pipeline system decreased to an average of 83.2 mbpd compared to 88.1 mbpd for the same period last year.
Revenues from our crude pipelines were $9.8 million, an increase of $2.2 million compared to the three months ended September 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 143.6 mbpd compared to 143.9 mbpd for the same period last year.
Revenues from terminal, tankage and loading rack fees were $12.2 million, an increase of $7.2 million compared to the three months ended September 30, 2009. This increase includes an increase of $7.1 million in revenues attributable to volumes transferred and stored at our Tulsa storage and rack facilities. Refined products terminalled in our facilities increased to an average of 226.9 mbpd compared to 166.9 mbpd for the same period last year.
Operations Expense
Operations expense for the three months ended September 30, 2010 increased by $2.5 million compared to the three months ended September 30, 2009. This increase was due principally to operating costs attributable to our December 2009 and March 2010 asset acquisitions, and higher maintenance and payroll expense.

 

- 33 -


Table of Contents

Depreciation and Amortization
Depreciation and amortization for the three months ended September 30, 2010 increased by $0.7 million compared to the three months ended September 30, 2009. This was due to increased depreciation attributable to our December 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 $0.7 million reduction in depreciation expense for the three months ended September 30, 2010.
General and Administrative
General and administrative costs for the three months ended September 30, 2010 decreased by $0.3 million compared to the three months ended September 30, 2009.
Equity in Earnings of SLC Pipeline
Our equity in earnings of the SLC Pipeline were $0.6 million and $0.7 million for the three months ended September 30, 2010 and 2009, respectively.
Interest Expense
Interest expense for the three months ended September 30, 2010 totaled $8.4 million, an increase of $2 million compared to the three months ended September 30, 2009. This increase reflects interest on our 8.25% senior notes. For the three months ended September 30, 2009, fair value adjustments to our interest rate swaps resulted in a $0.9 million increase in interest expense. Excluding the effects of these fair value adjustments, our aggregate effective interest rate was 6.9% for the three months ended September 30, 2010 compared to 5.2% 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 for the three months ended September 30, 2010 and 2009, 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 September 30, 2009 consists of earnings generated by Rio Grande of $1.1 million for the third quarter of 2009 and is presented net of earnings attributable to noncontrolling interest holders of $0.3 million.
Results of Operations — Nine Months ended September 30, 2010 Compared with Nine Months ended September 30, 2009
Summary
Income from continuing operations for the nine months ended September 30, 2010 was $40.4 million, a $6.1 million increase compared to the nine months ended September 30, 2009. This increase in overall earnings is due principally to overall increased shipments on our pipeline systems and earnings attributable to our 2009 and March 2010 asset acquisitions. These factors were partially offset by increased operating costs and expenses, and interest expense.
Revenues for the nine months ended September 30, 2010 include the recognition of $5.7 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 $9 million relating to deficiency payments associated with certain guaranteed shipping contracts were deferred during the nine months ended September 30, 2010. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels or in 2011 when shipping rights expire unused after a twelve-month period.

 

- 34 -


Table of Contents

Revenues
Total revenues from continuing operations for the nine months ended September 30, 2010 were $132.7 million, a $24.6 million increase compared to the nine months ended September 30, 2009. This increase is due principally to revenues attributable to our recent asset acquisitions and higher tariffs on affiliate shipments, partially offset by an $8.1 million decrease in previously deferred revenue realized. On a year-to-date basis, overall pipeline shipments were up 7%, 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 $55 million, a decrease of $7.3 million compared to the nine months ended September 30, 2009. This decrease is due principally to a $9.1 million decrease in previously deferred revenue realized that was partially offset by higher tariffs on affiliate shipments. Volumes shipped on our refined product pipeline system averaged 130.9 mbpd compared to 131.1 mbpd for the same period last year reflecting a decrease in third-party shipments, offset by an increase in affiliate shipments.
Revenues from our intermediate pipelines were $15.7 million, an increase of $4.2 million compared to the nine months ended September 30, 2009. This increase includes a $1 million increase in previously deferred revenue realized. Additionally, shipments on our intermediate product pipeline system increased to an average of 82.8 mbpd compared to 64.5 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 $28.9 million, an increase of $7.7 million compared to the nine months ended September 30, 2009. This increase is due principally to $6.9 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 140 mbpd during the nine months ended September 30, 2010 compared to 136.3 mbpd for the same period last year reflecting increased affiliate shipments.
Revenues from terminal, tankage and loading rack fees were $33.1 million, an increase of $20 million compared to the nine months ended September 30, 2009. This increase includes $19 million in revenues attributable to volumes transferred and stored at our Tulsa storage and rack facilities acquired in 2009 and March 2010. Refined products terminalled in our facilities increased to an average of 216.8 mbpd compared to 149.8 mbpd for the same period last year.
Operations Expense
Operations expense for the nine months ended September 30, 2010 increased by $8.1 million compared to the nine months ended September 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 costs.
Depreciation and Amortization
Depreciation and amortization for the nine months ended September 30, 2010 increased by $2.8 million compared to the nine months ended September 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 $2.2 million reduction in depreciation expense for the nine months ended September 30, 2010.

 

- 35 -


Table of Contents

General and Administrative
General and administrative costs for the nine months ended September 30, 2010 increased by $1 million compared to the nine months ended September 30, 2009, due principally to increased professional fees, including costs attributable to our March 2010 asset acquisitions.
Equity in Earnings of SLC Pipeline
The SLC Pipeline commenced pipeline operations effective March 2009. Our equity in earnings of the SLC Pipeline was $1.6 million and $1.3 million for the nine months ended September 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 nine months ended September 30, 2010 totaled $25.5 million, an increase of $9.3 million compared to the nine months ended September 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 nine months ended September 30, 2010 compared to $0.3 million for the nine months ended September 30, 2009. Excluding the effects of these fair value adjustments, our aggregate effective interest rate was 6.8% for the nine months ended September 30, 2010 compared to 5.2% for 2009 reflecting interest on our 8.25% senior notes issued in March 2010.
State Income Tax
We recorded state income taxes of $0.2 million and $0.3 million for the nine months ended September 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 nine months ended September 30, 2009 consists of earnings generated by Rio Grande of $4.1 million for the first nine months of 2009 and is presented net of earnings attributable to noncontrolling interest holders of $1.2 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 nine months ended September 30, 2010, we received advances totaling $52 million and repaid $101 million, resulting in the net repayment of $49 million in advances. As of September 30, 2010, we had $157 million outstanding under the Credit Agreement that was used to finance acquisitions and capital projects. The Credit Agreement expires in August 2011, therefore, outstanding borrowings all of which were previously classified as long-term liabilities are currently classified as current liabilities. We intend to renew the Credit Agreement prior to expiration and to continue to finance outstanding Credit Agreement borrowings. Upon renewal, outstanding borrowings not designated for working capital purposes will be reclassified as long-term debt.

 

- 36 -


Table of Contents

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.
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, May and August 2010 we paid regular quarterly cash distributions of $0.805, $0.815 and $0.825, on all units in an aggregate amount of $62.6 million. Included in these distributions were $7.4 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 nine months ended September 30, 2009, net cash flows from our discontinued Rio Grande operations were $5.7 million.
Cash and cash equivalents decreased by $1.8 million during the nine months ended September 30, 2010. The combined cash flows used for investing and financing activities of $43.6 million and $24.4 million, respectively, exceeded cash flows provided by operating activities of $66.1 million. Working capital for the nine months ended September 30, 2010 decreased by $159.8 million primarily due to the reclassification of $157 million in credit agreement borrowings to current liabilities.
Cash Flows — Operating Activities
Cash flows from operating activities increased by $21.3 million from $44.8 million for the nine months ended September 30, 2009 to $66.1 million for the nine months ended September 30, 2010. This increase is due principally to $29 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 nine months ended September 30, 2010, we received cash payments of $9.3 million under these commitments. We billed $5.7 million during the nine months ended September 30, 2009 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the nine months ended September 30, 2010. Another $2.4 million is included in our accounts receivable at September 30, 2010 related to shortfalls that occurred during the third quarter of 2010.
Cash Flows — Investing Activities
Cash flows used for investing activities decreased by $55.4 million from $99 million for the nine months ended September 30, 2009 to $43.6 million for the nine months ended September 30, 2010. During the nine months ended September 30, 2010, we acquired storage assets from Holly for $35.5 million and invested $8.1 million in additions to properties and equipment. For the nine months ended September 30, 2009, we acquired Holly’s 16-inch intermediate pipeline and the Tulsa loading racks for $46 million, acquired our SLC Pipeline joint venture interest costing $25.5 million, and invested $27.5 million in additions to properties and equipment.

 

- 37 -


Table of Contents

Cash Flows — Financing Activities
Cash flows used for financing activities were $24.4 million compared to cash provided by financing activities of $53 million for the nine months ended September 30, 2009, a decrease of $77.3 million. During the nine months ended September 30, 2010, we received $52 million and repaid $101 million in advances under the Credit Agreement. Additionally, we received $147.5 million in net proceeds and incurred $0.5 million in financing costs upon the issuance of the 8.25% Senior Notes. During the nine months ended September 30, 2010, we paid $62.6 million in regular quarterly cash distributions to our general and limited partners, paid $57.5 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 nine months ended September 30, 2009, we received $197 million and repaid $152 million in advances under the Credit Agreement. Additionally, we received $58.4 million in proceeds and incurred $0.3 million in costs with respect to our May 2009 equity offering. During the nine months ended September 30, 2009, we paid $44.4 million in regular quarterly cash distributions to our general and limited partners, paid $5.7 million in excess of Holly’s transferred basis in the Tulsa loading racks and paid $0.6 million for the purchase of common units for recipients of restricted grants. We also received a $1.2 million capital contribution from our general partner
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.
Pursuant to a term sheet with Holly, we are currently constructing five interconnecting pipelines between Holly’s Tulsa east and west refining facilities. The project is expected to cost approximately $25 million with completion in the first quarter of 2011. We are currently negotiating terms for a long-term agreement with Holly to transfer intermediate products via these pipelines that will commence upon completion of the project. In the event that we are unable to obtain such an agreement, Holly will reimburse us for the cost of the pipelines.
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 $300 million. This includes a project scope change that includes the construction of ethanol blending and storage facilities at the Cedar City terminal. The pipeline is in the final construction phase and is expected to be mechanically complete in the second quarter of 2011.

 

- 38 -


Table of Contents

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.
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 September 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 September 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 September 30, 2010, we are subject to a .30% commitment fee on the $143 million unused portion of the Credit Agreement.
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 have 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.

 

- 39 -


Table of Contents

The carrying amounts of our long-term debt are as follows:
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands)  
Credit Agreement
  $ 157,000     $ 206,000  
 
               
6.25% Senior Notes
               
Principal
    185,000       185,000  
Unamortized discount
    (1,679 )     (1,964 )
Unamortized premium — dedesignated fair value hedge
    1,531       1,791  
 
           
 
    184,852       184,827  
 
           
 
               
8.25% Senior Notes
               
Principal
    150,000        
Unamortized discount
    (2,288 )      
 
           
 
    147,712        
 
           
 
               
Total debt
    489,564       390,827  
 
               
Less credit agreement borrowings classified as current liabilities
    157,000        
 
           
 
               
Total long-term debt
  $ 332,564     $ 390,827  
 
           
See “Risk Management” for a discussion of our interest rate swaps.
Contractual Obligations
During the nine months ended September 30, 2010, we repaid net advances of $49 million resulting in $157 million of borrowings outstanding under the Credit Agreement at September 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 nine months ended September 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 near 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.

 

- 40 -


Table of Contents

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 September 30, 2010, we have an accrual of $0.3 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.

 

- 41 -


Table of Contents

RISK MANAGEMENT
We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.
As of September 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 September 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 loss. 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 loss to interest expense. To date, we have had no ineffectiveness on our cash flow hedge.
Additional information on our interest rate swap as of September 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   $ 11,825     Accumulated other comprehensive loss   $ 11,825  
 
                           
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 September 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 September 30, 2010, the fair value of our 6.25% Senior Notes and 8.25% Senior Notes were $183.2 million and $156.8 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 September 30, 2010 would result in a change of approximately $4.5 million and $6.4 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 September 30, 2010, borrowings outstanding under the Credit Agreement were $157 million. By means of our cash flow hedge, we have effectively converted the variable rate on $155 million of outstanding borrowings to a fixed rate of 5.49%.

 

- 42 -


Table of Contents

At September 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.

 

- 43 -


Table of Contents

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 September 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.

 

- 44 -


Table of Contents

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
         
  10.1    
Tulsa Refinery Interconnects Term Sheet dated August 9, 2010 (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K Current Report dated August 11, 2010, File No. 1-32225).
       
 
  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.

 

- 45 -


Table of Contents

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: October 29, 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)
   

 

- 46 -