Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

 

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

For the quarterly period ended June 30, 2011

OR

 

¨ 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

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

2828 N. Harwood, Suite 1300

Dallas, Texas 75201

(Address of principal executive offices)

(214) 871-3555

(Registrant’s telephone number, including area code)

100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915

(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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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  x    No  ¨

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

 

Large accelerated filer   ¨    Accelerated filer   x
Non-accelerated filer   ¨    Smaller reporting company   ¨

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

The number of the registrant’s outstanding common units at July 22, 2011 was 22,078,509.

 

 

 


Table of Contents

HOLLY ENERGY PARTNERS, L.P.

INDEX

 

PART I. FINANCIAL INFORMATION      3   
  FORWARD-LOOKING STATEMENTS      3   
  Item 1.    Financial Statements (Unaudited, except December 31, 2010 Balance Sheet)      4   
 

Consolidated Balance Sheets

     4   
 

Consolidated Statements of Income

     5   
 

Consolidated Statements of Cash Flows

     6   
 

Consolidated Statement of Partners’ Equity

     7   
 

Notes to Consolidated Financial Statements

     8   
  Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations      23   
  Item 3.    Quantitative and Qualitative Disclosures About Market Risks      39   
  Item 4.    Controls and Procedures      39   
PART II. OTHER INFORMATION      40   
  Item 1.    Legal Proceedings      40   
  Item 6.    Exhibits      40   
 

SIGNATURES

     41   
 

Index to Exhibits

     42   

 

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PART I. FINANCIAL INFORMATION

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-Q, including, but not limited to, those under “Results of Operations” and “Liquidity and Capital Resources” in Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I are forward-looking statements. Forward looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations. These statements are based on our beliefs and assumptions and those of our general partner using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurance that our expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

 

   

risks and uncertainties with respect to the actual quantities of petroleum products and crude oil shipped on our pipelines and/or terminalled in our terminals;

 

   

the economic viability of HollyFrontier 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, operational 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, 2010 in “Risk Factors” and in this Form 10-Q in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” All forward-looking statements included in this Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

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Item 1. Financial Statements

Holly Energy Partners, L.P.

Consolidated Balance Sheets

 

     June 30, 2011
(Unaudited)
    December 31,
2010
 
     (In thousands, except unit data)  

ASSETS

    

Current assets:

    

Cash and cash equivalents

   $ 1,402      $ 403   

Accounts receivable:

    

Trade

     2,600        3,544   

Affiliates

     16,156        18,964   
                
     18,756        22,508   

Prepaid and other current assets

     1,038        775   
                

Total current assets

     21,196        23,686   

Properties and equipment, net

     445,986        434,950   

Transportation agreements, net

     105,016        108,489   

Goodwill

     49,109        49,109   

Investment in SLC Pipeline

     25,519        25,437   

Other assets

     4,325        1,602   
                

Total assets

   $ 651,151      $ 643,273   
                

LIABILITIES AND PARTNERS’ EQUITY

    

Current liabilities:

    

Accounts payable:

    

Trade

   $ 3,924      $ 6,347   

Affiliates

     3,191        3,891   
                
     7,115        10,238   

Accrued interest

     7,521        7,517   

Deferred revenue

     5,319        10,437   

Accrued property taxes

     2,311        1,990   

Other current liabilities

     956        1,262   
                

Total current liabilities

     23,222        31,444   

Long-term debt

     518,818        491,648   

Other long-term liabilities

     9,164        10,809   

Partners’ equity:

    

Common unitholders (22,078,509 units issued and outstanding at June 30, 2011 and December 31, 2010)

     261,014        271,649   

General partner interest (2% interest)

     (152,595     (152,251

Accumulated other comprehensive loss

     (8,472     (10,026
                

Total partners’ equity

     99,947        109,372   
                

Total liabilities and partners’ equity

   $ 651,151      $ 643,273   
                

See accompanying notes.

 

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Holly Energy Partners, L.P.

Consolidated Statements of Income

(Unaudited)

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011     2010     2011     2010  
     (In thousands, except per unit data)  

Revenues:

        

Affiliates

   $ 37,139      $ 37,079      $ 71,246      $ 70,676   

Third parties

     13,801        8,404        24,711        15,503   
                                
     50,940        45,483        95,957        86,179   
                                

Operating costs and expenses:

        

Operations

     14,366        13,495        27,162        26,555   

Depreciation and amortization

     7,713        7,591        15,353        14,801   

General and administrative

     1,573        1,913        2,936        4,476   
                                
     23,652        22,999        45,451        45,832   
                                

Operating income

     27,288        22,484        50,506        40,347   

Other income (expense):

        

Equity in earnings of SLC Pipeline

     467        544        1,207        1,025   

Interest income

     —          2        —          5   

Interest expense

     (8,724     (9,549     (17,273     (17,093

Other expense

     —          —          (12     (7
                                
     (8,257     (9,003     (16,078     (16,070
                                

Income before income taxes

     19,031        13,481        34,428        24,277   

State income tax

     (18     (46     (246     (140
                                

Net income

     19,013        13,435        34,182        24,137   

Less general partner interest in net income, Including incentive distributions

     3,847        2,909        7,409        5,555   
                                

Limited partners’ interest in net income

   $ 15,166      $ 10,526      $ 26,773      $ 18,582   
                                

Limited partners’ per unit interest in earnings – basic and diluted:

   $ 0.69      $ 0.48      $ 1.21      $ 0.84   
                                

Weighted average limited partners’ units outstanding

     22,079        22,079        22,079        22,079   
                                

See accompanying notes.

 

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Holly Energy Partners, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

 

     Six Months Ended
June 30,
 
     2011     2010  
     (In thousands)  

Cash flows from operating activities

    

Net income

   $ 34,182      $ 24,137   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation and amortization

     15,353        14,801   

Equity in earnings of SLC Pipeline, net of distributions

     (82     100   

Change in fair value – interest rate swaps

     —          1,464   

Amortization of restricted and performance units

     1,080        1,339   

(Increase) decrease in current assets:

    

Accounts receivable – trade

     944        (1,696

Accounts receivable – affiliates

     2,808        (2,625

Prepaid and other current assets

     (263     (200

Current assets of discontinued operations

     —          2,195   

Increase (decrease) in current liabilities:

    

Accounts payable – trade

     (2,423     (372

Accounts payable – affiliates

     (700     501   

Accrued interest

     4        4,825   

Deferred revenue

     (5,118     2,521   

Accrued property taxes

     321        (82

Other current liabilities

     (306     (656

Other, net

     489        (1,066
                

Net cash provided by operating activities

     46,289        45,186   
                

Cash flows from investing activities

    

Additions to properties and equipment

     (22,900     (4,487

Acquisition of assets from HollyFrontier Corporation

     —          (39,040
                

Net cash used for investing activities

     (22,900     (43,527
                

Cash flows from financing activities

    

Borrowings under credit agreement

     64,000        39,000   

Repayments of credit agreement borrowings

     (37,000     (90,000

Proceeds from issuance of senior notes

     —          147,540   

Distributions to HEP unitholders

     (44,862     (41,312

Purchase price in excess of transferred basis in assets acquired from HollyFrontier Corporation

     —          (53,960

Purchase of units for incentive grants

     (1,379     (2,276

Deferred financing costs

     (3,149     (353
                

Net cash used for financing activities

     (22,390     (1,361
                

Cash and cash equivalents

    

Increase for the period

     999        298   

Beginning of period

     403        2,508   
                

End of period

   $ 1,402      $ 2,806   
                

See accompanying notes.

 

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Holly Energy Partners, L.P.

Consolidated Statement of Partners’ Equity

(Unaudited)

 

     Common
Units
    General
Partner

Interest
    Accumulated
Other
Comprehensive
Loss
    Total  

Balance December 31, 2010

   $ 271,649      $ (152,251   $ (10,026   $ 109,372   

Distributions to HEP unitholders

     (37,525     (7,337     —          (44,862

Purchase of units for restricted grants

     (1,379     —          —          (1,379

Amortization of restricted and performance units

     1,080        —          —          1,080   

Comprehensive income:

        

Net income

     27,189        6,993        —          34,182   

Other comprehensive income

     —          —          1,554        1,554   
                                

Comprehensive income

     27,189        6,993        1,554        35,736   
                                

Balance June 30, 2011

   $ 261,014      $ (152,595   $ (8,472   $ 99,947   
                                

See accompanying notes.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1: Description of Business and Presentation of Financial Statements

Holly Energy Partners, L.P. (“HEP”) together with its consolidated subsidiaries, is a publicly held master limited partnership, currently 34% owned (including the 2% general partner interest) by HollyFrontier Corporation (formerly known as Holly Corporation) (“HFC”) and its subsidiaries. HFC changed its name in connection with the consummation of its merger of equals with Frontier Oil Corporation effective July 1, 2011. All previous references to “Holly” within these financial statements have been replaced with “HFC.”

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 pipelines and terminal, tankage and loading rack facilities that support HFC’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 U.S. generally accepted accounting principles (“GAAP”) 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, 2010. 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, 2011.

Note 2: Acquisitions

2010 Acquisitions

Tulsa East / Lovington Storage Asset Transaction

On March 31, 2010, we acquired from HFC 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 HFC’s Tulsa refinery east facility.

Also, as part of this same transaction, we acquired HFC’s asphalt loading rack facility located at its Navajo refinery facility in Lovington, New Mexico for $4.4 million.

 

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We are a consolidated variable interest entity of HFC. In accounting for these acquisitions from HFC, we recorded total property and equipment at HFC’s cost basis of $39 million and the purchase price in excess of HFC’s basis in the assets of $54 million as a decrease to our partners’ equity.

Note 3: 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 borrowings outstanding under our $275 million 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 $186 million carrying amount of borrowings outstanding under the Credit Agreement 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 $184.1 million and $159.4 million, respectively, at June 30, 2011. These fair value estimates are based on market quotes provided from a third-party bank. See Note 7 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. GAAP categorizes inputs used in fair value measurements into three broad levels as follows:

 

   

(Level 1) Quoted prices in active markets for identical assets or liabilities.

 

   

(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.

 

   

(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.

We have an interest rate swap that is measured at fair value on a recurring basis using Level 2 inputs that as of June 30, 2011 represented a liability having a fair value of $8.5 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 7 for additional information on our interest rate swap.

Note 4: Properties and Equipment

 

     June 30,      December 31,  
     2011      2010  
     (In thousands)  

Pipelines and terminals

   $ 510,488       $ 507,260   

Land and right of way

     25,271         25,264   

Other

     15,427         14,591   

Construction in progress

     35,391         16,601   
                 
     586,577         563,716   

Less accumulated depreciation

     140,591         128,766   
                 
   $ 445,986       $ 434,950   
                 

We capitalized $0.5 million and $0.2 million in interest related to major construction projects during the six months ended June 30, 2011 and 2010, respectively.

 

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Note 5: 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 HFC crude pipelines and tankage agreement (the “HFC CPTA”) represents a portion of the total purchase price of certain crude pipelines and tankage assets acquired from HFC in 2008 (at which time we were not a consolidated variable interest entity of HFC) 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 HFC CPTA.

The carrying amounts of our transportation agreements are as follows:

 

     June 30,
2011
     December 31,
2010
 
     (In thousands)  

Alon transportation agreement

   $ 59,933       $ 59,933   

HFC crude pipelines and tankage agreement

     74,231         74,231   
                 
     134,164         134,164   

Less accumulated amortization

     29,148         25,675   
                 
   $ 105,016       $ 108,489   
                 

We have additional transportation agreements with HFC that relate to assets contributed to us or acquired from HFC consisting of pipeline, terminal and tankage assets. These transactions occurred while we were a consolidated variable interest entity of HFC, therefore, our basis in these agreements does not reflect a step-up in basis to fair value.

In addition, we have an agreement to provide transportation and storage services to HFC via our Tulsa logistics and storage assets acquired from Sinclair. Since this agreement is with HFC and not between Sinclair and us, there is no purchase price allocation attributable to this agreement.

Note 6: Employees, Retirement and Incentive Plans

Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., a HFC 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 HFC. These employees participate in the retirement and benefit plans of HFC. Our share of retirement and benefit plan costs was $0.7 million and $0.6 million for the three months ended June 30, 2011 and 2010, respectively, and $1.4 million and $1.3 million for the six months ended June 30, 2011 and June 30, 2010, 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.

 

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As of June 30, 2011, 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 $0.3 million for the three months ended June 30, 2011 and 2010, respectively, and $1.1 million and $1.3 million for the six months ended June 30, 2011 and 2010, respectively. We currently purchase units in the open market instead of issuing new units for the settlement of all unit awards under our Long-Term Incentive Plan. At June 30, 2011, 350,000 units were authorized to be granted under the equity-based compensation plans, of which 83,254 had not yet been granted, assuming no forfeitures of the unvested units and full achievement of goals for the performance units already granted.

Restricted Units

Under our Long-Term Incentive Plan, we grant restricted units to selected employees and directors who perform services for us, with vesting generally over a period of one to five years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution and voting rights on these units from the date of grant. The fair value of each restricted unit award is measured at the market price as of the date of grant and is amortized over the vesting period.

A summary of restricted unit activity and changes during the six months ended June 30, 2011 is presented below:

 

Restricted Units

   Grants     Weighted-
Average
Grant-Date
Fair Value
     Weighted-
Average
Remaining
Contractual
Term
     Aggregate
Intrinsic
Value
($000)
 

Outstanding at January 1, 2011 (nonvested)

     47,295      $ 37.47         

Granted

     17,780        59.65         

Vesting and transfer of full ownership to recipients

     (24,055     41.48         

Forfeited

     (7,802     48.29         
                

Outstanding at June 30, 2011 (nonvested)

     33,218      $ 44.97         1 year       $ 1,803   
                                  

The fair value of restricted units that were vested and transferred to recipients during the six months ended June 30, 2011 and 2010 were $1 million and $1.5 million, respectively. As of June 30, 2011, 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 1 year.

Performance Units

Under our Long-Term Incentive Plan, we grant performance units to selected executives who perform services for us. Performance units granted in 2011 and 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 are payable based upon the growth in distributions on our common units during the requisite period, and vest over a period of three years. As of June 30, 2011, estimated share payouts for outstanding nonvested performance unit awards ranged from 110% to 120%.

We granted 8,969 performance units to certain officers in March 2011. These units will vest over a three-year performance period ending December 31, 2013 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 $59.65 and will apply to the number of units ultimately awarded.

 

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A summary of performance unit activity and changes during the six months ended June 30, 2011 is presented below:

 

Performance Units

   Payable
In Units
 

Outstanding at January 1, 2011 (nonvested)

     59,415   

Granted

     8,969   

Vesting and transfer of common units to recipients

     (14,337

Forfeited

     —     
        

Outstanding at June 30, 2011 (nonvested)

     54,047   
        

The fair value of performance units vested and transferred to recipients during the six months ended June 30, 2011 and 2010 was $0.6 million and $0.5 million, respectively. Based on the weighted average grant-date fair value, there were $1 million of total unrecognized compensation costs related to nonvested performance units at June 30, 2011. That cost is expected to be recognized over a weighted-average period of 1.1 years.

During the six months ended June 30, 2011, we paid $1.4 million for the purchase of our common units in the open market for the issuance and settlement of all unit awards under our Long-Term Incentive Plan.

Note 7: Debt

Credit Agreement

We have a $275 million Credit Agreement that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $30 million sub-limit. In February 2011, we amended our previous credit agreement (expiring in August 2011), extending the expiration date and slightly reducing the size of the credit facility from $300 million to $275 million. The size was reduced based on management’s review of past and forecasted utilization of the facility. The Credit Agreement expires in February 2016; however, in the event that the 6.25% Senior Notes are not repurchased, refinanced, extended or repaid prior to September 1, 2014, the Credit Agreement shall expire on that date.

During the six months ended June 30, 2011, we received advances totaling $64 million and repaid $37 million, resulting in net borrowings of $27 million under the Credit Agreement and an outstanding balance of $186 million at June 30, 2011.

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 material, 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.

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 1.00% to 2.00%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 2.00% to 3.00%). 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). We incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.375% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.

 

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The Credit Agreement imposes certain requirements on us which we are subject to and currently in compliance with, 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, total debt to EBITDA ratio and senior 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.

Senior Notes

In March 2010, we issued $150 million in aggregate principal amount outstanding 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 HFC 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 outstanding 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.

The carrying amounts of our debt are as follows:

 

     June 30,
2011
    December 31,
2010
 
     (In thousands)  

Credit Agreement

   $ 186,000      $ 159,000   

6.25% Senior Notes

    

Principal

     185,000        185,000   

Unamortized discount

     (1,394     (1,584

Unamortized premium – dedesignated fair value hedge

     1,271        1,444   
                
     184,877        184,860   
                

8.25% Senior Notes

    

Principal

     150,000        150,000   

Unamortized discount

     (2,059     (2,212
                
     147,941        147,788   
                

Total long-term debt

   $ 518,818      $ 491,648   
                

Interest Rate Risk Management

We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

As of June 30, 2011, 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 2.50%, which equals an effective interest rate of 6.24% as of June 30, 2011. This swap contract matures in February 2013.

 

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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 $155 million of our 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 $155 million of our 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 is as follows:

 

Derivative Instrument

 

Balance Sheet

Location

  Fair Value    

Location of Offsetting
Balance

  Offsetting
Amount
 
    (In thousands)  

June 30, 2011

       

Interest rate swap designated as cash flow hedging instrument:

     

Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)

 

Other long-term liabilities

  $ 8,472     

Accumulated other comprehensive loss

  $ 8,472   
                   

December 31, 2010

       

Interest rate swap designated as cash flow hedging instrument:

     

Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)

 

Other long-term liabilities

  $ 10,026     

Accumulated other comprehensive loss

  $ 10,026   
                   

Interest Expense and Other Debt Information

Interest expense consists of the following components:

 

     Six Months Ended June 30,  
     2011      2010  
     (In thousands)  

Interest on outstanding debt:

     

Credit Agreement, net of interest on interest rate swap

   $ 5,013       $ 4,726   

6.25% Senior Notes, net of interest on interest rate swaps

     5,781         5,623   

8.25% Senior Notes

     6,187         3,816   

Partial settlement of interest rate swap – cash flow hedge

     —           1,076   

Net fair value adjustments to interest rate swaps (1)

     —           1,464   

Net amortization of discount and deferred debt issuance costs

     595         458   

Commitment fees

     227         177   
                 

Total interest incurred

     17,803         17,340   

Less capitalized interest

     530         247   
                 

Net interest expense

   $ 17,273       $ 17,093   
                 

Cash paid for interest (2)

   $ 17,204       $ 14,192   
                 

 

(1) Represents fair value adjustments to interest rate swap agreements settled during the first quarter of 2010.
(2) Net of cash received under previous interest rate swap agreements of $1.9 million for the six months ended June 30, 2010.

Note 8: Significant Customers

All revenues are domestic revenues, of which 96% are currently generated from our two largest customers: HFC and Alon. The vast majority of our revenues are derived from activities conducted in the southwest United States.

 

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The following table presents the percentage of total revenues generated by each of these customers:

 

     Three Months Ended
June  30,
    Six Months Ended
June  30,
 
     2011     2010     2011     2010  

HFC

     73     82     74     82

Alon

     23     14     22     14

 

(1) The Alon PTA was amended in June 2011, limiting the carryover term of credits attributable to Alon’s shortfall payments to the calendar year end in which the shortfalls occur. As a result, we recognized an additional $2.4 million of previously deferred revenues during the three months ended June 30, 2011 that relate to shortfall billings for the third and fourth quarters of 2010.

Note 9: Related Party Transactions

HFC Agreements

We serve HFC’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

 

   

HFC PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to assets contributed to us by HFC upon our initial public offering in 2004);

 

   

HFC IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to assets acquired from HFC in 2005 and 2009);

 

   

HFC CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to assets acquired from HFC in 2008);

 

   

HFC 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 HFC in March 2010);

 

   

HFC RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from HFC in 2009);

 

   

HFC ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west facilities acquired from HFC in 2009);

 

   

HFC NPA (natural gas pipeline throughput agreement expiring in 2024); and

 

   

HFC ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to the Lovington rack facility acquired from HFC in March 2010).

Under these agreements, HFC 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 are subject to annual tariff rate adjustments on July 1, based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of July 1, 2011, these agreements with HFC will result in minimum annualized payments to us of $140 million.

If HFC fails to meet its 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 HFC PTA and HFC IPA may be applied as a credit in the following four quarters after minimum obligations are met.

Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”) we pay HFC an annual administrative fee for the provision by HFC or its affiliates of various general and administrative services to us, currently $2.3 million. This fee does not include the salaries of pipeline and terminal personnel or the cost of their employee benefits, which are charged to us separately by HFC. Also, we reimburse HFC and its affiliates for direct expenses they incur on our behalf.

 

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Related party transactions with HFC are as follows:

 

 

Revenues received from HFC were $37.1 million for the three months ended June 30, 2011 and 2010, and $71.2 million and $70.7 million for the six months ended June 30, 2011 and 2010, respectively.

 

 

HFC charged general and administrative services under the Omnibus Agreement of $0.6 million for the three months ended June 30, 2011 and 2010 and $1.2 million for the six months ended June 30, 2011 and 2010.

 

 

We reimbursed HFC for costs of employees supporting our operations of $4.7 million and $4.6 million for the three months ended June 30, 2011 and 2010, respectively, and $9.7 million and $8.8 million for the six months ended June 30, 2011 and 2010, respectively.

 

 

We distributed $10 million and $8.8 million for the three months ended June 30, 2011 and 2010, respectively, to HFC as regular distributions on its common units, and general partner interest, including general partner incentive distributions. We distributed $19.7 million and $17.4 million for the six months ended June 30, 2011 and 2010, respectively.

 

 

Accounts receivable from HFC were $16.2 million and $19 million at June 30, 2011 and December 31, 2010, respectively.

 

 

Accounts payable to HFC were $3.2 million and $3.9 million at June 30, 2011 and December 31, 2010, respectively.

 

 

Revenues for the three and the six months ended June 30, 2011 include $0.7 million and $1.9 million, respectively, of shortfalls billed under the HFC IPA in 2010, as HFC did not exceed its minimum volume commitment in any of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at June 30, 2011 and December 31, 2010, includes $3.9 million and $3.3 million, respectively, relating to the HFC IPA. It is possible that HFC may not exceed its minimum obligations under the HFC IPA to allow HFC to receive credit for any of the $3.9 million deferred at June 30, 2011.

 

 

We acquired certain storage assets and an asphalt loading rack facility from HFC in March 2010. See Note 2 for a description of this transaction.

Note 10: Partners’ Equity

HFC currently holds 7,290,000 of our common units and the 2% general partner interest, which together constitutes a 34% ownership interest in us.

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 in connection with our acquisition of assets from Alon in 2005 were met and the units were converted into our common units on a one-for-one basis. These subordinated units were not publicly traded.

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.

 

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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 for the periods presented below:

 

     Three Months Ended
June  30,
     Six Months Ended
June 30,
 
     2011      2010      2011      2010  
     (In thousands, except per unit data)  

General partner interest in net income

   $ 310       $ 220       $ 547       $ 388   

General partner incentive distribution

     3,537         2,689         6,862         5,167   
                                   

Total general partner interest in net income attributable to HEP

   $ 3,847       $ 2,909       $ 7,409       $ 5,555   
                                   

Cash Distributions

Our general partner, HEP Logistics Holdings, L.P., is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels.

On July 27, 2011, we announced our cash distribution for the second quarter of 2011 of $0.865 per unit. The distribution is payable on all common and general partner units and will be paid August 12, 2011 to all unitholders of record on August 8, 2011.

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
June  30,
     Six Months Ended
June 30,
 
     2011      2010      2011      2010  
     (In thousands, except per unit data)  

General partner interest

   $ 462       $ 427       $ 915       $ 844   

General partner incentive distribution

     3,537         2,689         6,862         5,167   
                                   

Total general partner distribution

     3,999         3,116         7,777         6,011   

Limited partner distribution

     19,098         18,215         37,975         36,209   
                                   

Total regular quarterly cash distribution

   $ 23,097       $ 21,331       $ 45,752       $ 42,220   
                                   

Cash distribution per unit applicable to limited partners

   $ 0.865       $ 0.825       $ 1.720       $ 1.640   
                                   

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 our equity since our regular quarterly distributions have exceeded our quarterly net income. Additionally, if the assets contributed and acquired from HFC had occurred while we were not a consolidated variable interest entity of HFC, our acquisition cost in excess of HFC’s historical basis in the transferred assets of $218 million would have been recorded in our financial statements as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.

 

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Comprehensive Income

We have other comprehensive income resulting from fair value adjustments to our cash flow hedge. Our comprehensive income is as follows:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010     2011      2010  
     (In thousands)  

Net income

   $ 19,013       $ 13,435      $ 34,182       $ 24,137   

Other comprehensive income (loss):

          

Change in fair value of cash flow hedge

     271         (1,696     1,554         (3,057

Reclassification adjustment to net income on partial settlement of cash flow hedge

     —           1,076        —           1,076   
                                  

Other comprehensive income (loss)

     271         (620     1,554         (1,981
                                  

Comprehensive income

   $ 19,284       $ 12,815      $ 35,736       $ 22,156   
                                  

Note 11: 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.

The following financial information presents condensed consolidating balance sheets, statements of income, and statements of cash flows of the Parent and the Guarantor Subsidiaries. The information has been presented as if the Parent accounted for its ownership in the Guarantor Subsidiaries using the equity method of accounting.

 

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Condensed Consolidating Balance Sheet

 

June 30, 2011

   Parent     Guarantor
Subsidiaries
     Eliminations     Consolidated  
     (In thousands)  

ASSETS

         

Current assets:

         

Cash and cash equivalents

   $ 2      $ 1,400       $ —        $ 1,402   

Accounts receivable

     —          18,756         —          18,756   

Intercompany accounts receivable (payable)

     (151,277     151,277         —          —     

Prepaid and other current assets

     73        965         —          1,038   
                                 

Total current assets

     (151,202     172,398         —          21,196   

Properties and equipment, net

     —          445,986         —          445,986   

Investment in subsidiaries

     590,944        —           (590,944     —     

Transportation agreements, net

     —          105,016         —          105,016   

Goodwill

     —          49,109         —          49,109   

Investment in SLC Pipeline

     —          25,519         —          25,519   

Other assets

     1,156        3,169         —          4,325   
                                 

Total assets

   $ 440,898      $ 801,197       $ (590,944   $ 651,151   
                                 

LIABILITIES AND PARTNERS’ EQUITY

         

Current liabilities:

         

Accounts payable

   $ —        $ 7,115       $ —        $ 7,115   

Accrued interest

     7,498        23         —          7,521   

Deferred revenue

     —          5,319         —          5,319   

Accrued property taxes

     —          2,311         —          2,311   

Other current liabilities

     635        321         —          956   
                                 

Total current liabilities

     8,133        15,089         —          23,222   

Long-term debt

     332,818        186,000         —          518,818   

Other long-term liabilities

     —          9,164         —          9,164   

Partners’ equity

     99,947        590,944         (590,944     99,947   
                                 

Total liabilities and partners’ equity

   $ 440,898      $ 801,197       $ (590,944   $ 651,151   
                                 

 

Condensed Consolidating Balance Sheet

 

         

December 31, 2010

   Parent     Guarantor
Subsidiaries
     Eliminations     Consolidated  
     (In thousands)  

ASSETS

         

Current assets:

         

Cash and cash equivalents

   $ 2      $ 401       $ —        $ 403   

Accounts receivable

     —          22,508         —          22,508   

Intercompany accounts receivable (payable)

     (92,230     92,230         —          —     

Prepaid and other current assets

     235        540         —          775   
                                 

Total current assets

     (91,993     115,679         —          23,686   

Properties and equipment, net

     —          434,950         —          434,950   

Investment in subsidiaries

     541,262        —           (541,262     —     

Transportation agreements, net

     —          108,489         —          108,489   

Goodwill

     —          49,109         —          49,109   

Investment in SLC Pipeline

     —          25,437         —          25,437   

Other assets

     1,261        341         —          1,602   
                                 

Total assets

   $ 450,530      $ 734,005       $ (541,262   $ 643,273   
                                 

LIABILITIES AND PARTNERS’ EQUITY

         

Current liabilities:

         

Accounts payable

   $ —        $ 10,238       $ —        $ 10,238   

Accrued interest

     7,498        19         —          7,517   

Deferred revenue

     —          10,437         —          10,437   

Accrued property taxes

     —          1,990         —          1,990   

Other current liabilities

     1,011        251         —          1,262   
                                 

Total current liabilities

     8,509        22,935         —          31,444   

Long-term debt

     332,649        158,999         —          491,648   

Other long-term liabilities

     —          10,809         —          10,809   

Partners’ equity

     109,372        541,262         (541,262     109,372   
                                 

Total liabilities and partners’ equity

   $ 450,530      $ 734,005       $ (541,262   $ 643,273   
                                 

 

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Condensed Consolidating Statement of Income

 

Three Months Ended June 30, 2011

   Parent     Guarantor
Subsidiaries
    Eliminations     Consolidated  
     (In thousands)  

Revenues:

        

Affiliates

   $ —        $ 37,139      $ —        $ 37,139   

Third parties

     —          13,801        —          13,801   
                                
     —          50,940        —          50,940   

Operating costs and expenses:

        

Operations

     —          14,366        —          14,366   

Depreciation and amortization

     —          7,713        —          7,713   

General and administrative

     952        621        —          1,573   
                                
     952        22,700        —          23,652   
                                

Operating income (loss)

     (952     28,240        —          27,288   

Equity in earnings of subsidiaries

     26,086        —          (26,086     —     

Equity in earnings of SLC Pipeline

     —          467        —          467   

Interest income (expense)

     (6,121     (2,603     —          (8,724
                                
     19,965        (2,136     (26,086     (8,257
                                

Income before income taxes

     19,013        26,104        (26,086     19,031   

State income tax

     —          (18     —          (18
                                

Net income

   $ 19,013      $ 26,086      $ (26,086   $ 19,013   
                                

Condensed Consolidating Statement of Income

 

                        

Three Months Ended June 30, 2010

   Parent     Guarantor
Subsidiaries
    Eliminations     Consolidated  
     (In thousands)  

Revenues:

        

Affiliates

   $ —        $ 37,079      $ —        $ 37,079   

Third parties

     —          8,404        —          8,404   
                                
     —          45,483        —          45,483   

Operating costs and expenses:

        

Operations

     —          13,495        —          13,495   

Depreciation and amortization

     —          7,591        —          7,591   

General and administrative

     1,281        632        —          1,913   
                                
     1,281        21,718        —          22,999   
                                

Operating income (loss)

     (1,281     23,765        —          22,484   

Equity in earnings of subsidiaries

     20,833        —          (20,833     —     

Equity in earnings of SLC Pipeline

     —          544        —          544   

Interest income (expense)

     (6,117     (3,430     —          (9,547
                                
     14,716        (2,886     (20,833     (9,003
                                

Income before income taxes

     13,435        20,879        (20,833     13,481   

State income tax

     —          (46     —          (46
                                

Net income

   $ 13,435      $ 20,833      $ (20,833   $ 13,435   
                                

 

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Condensed Consolidating Statement of Income

 

Six Months Ended June 30, 2011

   Parent     Guarantor
Subsidiaries
    Eliminations     Consolidated  
     (In thousands)  

Revenues:

        

Affiliates

   $ —        $ 71,246      $ —        $ 71,246   

Third parties

     —          24,711        —          24,711   
                                
     —          95,957        —          95,957   

Operating costs and expenses:

        

Operations

     —          27,162        —          27,162   

Depreciation and amortization

     —          15,353        —          15,353   

General and administrative

     1,703        1,233        —          2,936   
                                
     1,703        43,748        —          45,451   
                                

Operating income (loss)

     (1,703     52,209        —          50,506   

Equity in earnings of subsidiaries

     48,128        —          (48,128     —     

Equity in earnings of SLC Pipeline

     —          1,207        —          1,207   

Interest income (expense)

     (12,243     (5,030     —          (17,273

Other

     —          (12     —          (12
                                
     35,885        (3,835     (48,128     (16,078
                                

Income before income taxes

     34,182        48,374        (48,128     34,428   

State income tax

     —          (246     —          (246
                                

Net income

   $ 34,182      $ 48,128      $ (48,128   $ 34,182   
                                

Condensed Consolidating Statement of Income

 

                        

Six Months Ended June 30, 2010

   Parent     Guarantor
Subsidiaries
    Eliminations     Consolidated  
     (In thousands)  

Revenues:

        

Affiliates

   $ —        $ 70,676      $ —        $ 70,676   

Third parties

     —          15,503        —          15,503   
                                
     —          86,179        —          86,179   

Operating costs and expenses:

        

Operations

     —          26,555        —          26,555   

Depreciation and amortization

     —          14,801        —          14,801   

General and administrative

     3,082        1,394        —          4,476   
                                
     3,082        42,750        —          45,832   
                                

Operating income (loss)

     (3,082     43,429        —          40,347   

Equity in earnings of subsidiaries

     38,318        —          (38,318     —     

Equity in earnings of SLC Pipeline

     —          1,025        —          1,025   

Interest income (expense)

     (11,099     (5,989     —          (17,088

Other

     —          (7     —          (7
                                
     27,219        (4,971     (38,318     (16,070
                                

Income before income taxes

     24,137        38,458        (38,318     24,277   

State income tax

     —          (140     —          (140
                                

Net income

   $ 24,137      $ 38,318      $ (38,318   $ 24,137   
                                

 

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Condensed Consolidating Statement of Cash Flows

 

Six Months Ended June 30, 2011

   Parent     Guarantor
Subsidiaries
    Eliminations      Consolidated  
     (In thousands)  

Cash flows from operating activities

   $ 46,241      $ 48      $ —         $ 46,289   

Cash flows from investing activities

         

Additions to properties and equipment

     —          (22,900     —           (22,900

Cash flows from financing activities

         

Net borrowings under credit agreement

     —          27,000        —           27,000   

Distributions to HEP unitholders

     (44,862     —          —           (44,862

Purchase of units for restricted grants

     (1,379     —          —           (1,379

Deferred financing costs

     —          (3,149     —           (3,149
                                 
     (46,241     23,851        —           (22,390
                                 

Cash and cash equivalents

         

Increase for the period

     —          999        —           999   

Beginning of period

     2        401        —           403   
                                 

End of period

   $ 2      $ 1,400      $ —         $ 1,402   
                                 

Condensed Consolidating Statement of Cash Flows

 

      

Six Months Ended June 30, 2010

   Parent     Guarantor
Subsidiaries
    Eliminations      Consolidated  
     (in thousands)  

Cash flows from operating activities

   $ (103,599   $ 148,785      $ —         $ 45,186   

Cash flows from investing activities

         

Additions to properties and equipment

     —          (4,487     —           (4,487

Acquisition of assets from HFC

     —          (39,040     —           (39,040
                                 
     —          (43,527     —           (43,527
                                 

Cash flows from financing activities

         

Net repayments under credit agreement

     —          (51,000     —           (51,000

Net proceeds from issuance of senior notes

     147,540        —          —           147,540   

Distributions to HEP unitholders

     (41,312     —          —           (41,312

Purchase price in excess of transferred basis

in assets acquired from HFC

     —          (53,960     —           (53,960

Purchase of units for restricted grants

     (2,276     —          —           (2,276

Deferred financing costs

     (353     —          —           (353
                                 
     103,599        (104,960     —           (1,361
                                 

Cash and cash equivalents

         

Increase for the period

     —          298        —           298   

Beginning of period

     2        2,506        —           2,508   
                                 

End of period

   $ 2      $ 2,804      $ —         $ 2,806   
                                 

 

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HOLLY ENERGY PARTNERS, L.P.

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 2, including but not limited to the sections on “Results of Operations” and “Liquidity and Capital Resources,” contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I of this Quarterly Report on Form 10-Q. In this document, the words “we,” “our,” “ours” and “us” refer to Holly Energy Partners, L.P. (“HEP”) and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.

OVERVIEW

HEP is a Delaware limited partnership. We own and operate petroleum product and crude oil pipeline and terminal, tankage and loading rack facilities that support the refining and marketing operations of HollyFrontier Corporation (formerly known as Holly Corporation) (“HFC”) in west Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. HFC and its subsidiaries currently own a 34% interest in us including the 2% general partnership interest. HFC changed its name in connection with the consummation of its merger of equals with Frontier Oil Corporation effective July 1, 2011. All previous references to “Holly” within this document have been replaced with “HFC.”

We also own and operate refined product pipelines and terminals, located primarily in Texas, that service Alon’s (“Alon”) Big Spring refinery in Big Spring, Texas. Additionally, we own a 25% joint venture interest in the SLC Pipeline (the “SLC Pipeline”), a 95-mile intrastate crude oil pipeline system 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 HFC 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 HFC’s Tulsa refinery east facility and an asphalt loading rack facility located at HFC’s Navajo refinery facility in Lovington, New Mexico.

Agreements with HFC and Alon

We serve HFC’s refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline and terminal, tankage and throughput agreements:

 

   

HFC PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to assets contributed to us by HFC upon our initial public offering in 2004);

 

   

HFC IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to assets acquired from HFC in 2005 and 2009);

 

   

HFC CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that relates to assets acquired from HFC in 2008);

 

   

HFC 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 HFC in March 2010);

 

   

HFC RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner Pipeline acquired from HFC in 2009);

 

   

HFC ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa west facilities acquired from HFC in 2009);

 

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HFC NPA (natural gas pipeline throughput agreement expiring in 2024); and

 

   

HFC ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to the Lovington rack facility acquired from HFC in March 2010).

Under these agreements, HFC 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 are subject to annual tariff rate adjustments on July 1, based on the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of July 1, 2011, these agreements with HFC will result in minimum annualized payments to us of $140 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 that is also subject to annual tariff rate adjustments.

We have a capacity lease agreement with Alon under which we lease Alon space on our Orla to El Paso pipeline for the shipment of up to 17,500 barrels of refined product per day. The terms under this agreement expire beginning in 2012 through 2018.

As of July 1, 2011, contractual minimums under our long-term service agreements are as follows:

 

Agreement

   Minimum  Annualized
Commitment

(In millions)
     Year of Maturity   

Contract Type

HFC PTA

   $ 45.6       2019    Minimum revenue commitment

HFC IPA

     21.6       2024    Minimum revenue commitment

HFC CPTA

     29.6       2023    Minimum revenue commitment

HFC PTTA

     29.8       2024    Minimum revenue commitment

HFC RPA

     9.5       2024    Minimum revenue commitment

HFC ETA

     2.8       2024    Minimum revenue commitment

HFC ATA

     0.5       2025    Minimum revenue commitment

HFC NPA

     0.6       2024    Minimum revenue commitment

Alon PTA

     23.4       2020    Minimum volume commitment

Alon capacity lease

     6.6       Various    Capacity lease
              

Total

   $ 170.0         
              

A significant reduction in revenues under these agreements would have a material adverse effect on our results of operations.

Under certain provisions of an omnibus agreement (“Omnibus Agreement”) that we have with HFC, we pay HFC an annual administrative fee, currently $2.3 million, for the provision by HFC 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 HFC. We also reimburse HFC and its affiliates for direct expenses they incur on our behalf.

 

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RESULTS OF OPERATIONS (Unaudited)

Income, Distributable Cash Flow and Volumes

The following tables present income, distributable cash flow and volume information for the three and the six months ended June 30, 2011 and 2010.

 

     Three Months Ended
June 30,
    Change
from

2010
 
     2011     2010    
     (In thousands, except per unit data)  

Revenues

      

Pipelines:

      

Affiliates – refined product pipelines

   $ 11,689      $ 12,067      $ (378

Affiliates – intermediate pipelines

     5,069        4,964        105   

Affiliates – crude pipelines

     9,624        9,728        (104
                        
     26,382        26,759        (377

Third parties – refined product pipelines

     11,906        6,455        5,451   
                        
     38,288        33,214        5,074   

Terminals and loading racks:

      

Affiliates

     10,757        10,320        437   

Third parties

     1,895        1,949        (54
                        
     12,652        12,269        383   
                        

Total revenues

     50,940        45,483        5,457   

Operating costs and expenses

      

Operations

     14,366        13,495        871   

Depreciation and amortization

     7,713        7,591        122   

General and administrative

     1,573        1,913        (340
                        
     23,652        22,999        653   
                        

Operating income

     27,288        22,484        4,804   

Equity in earnings of SLC Pipeline

     467        544        (77

Interest income

     —          2        (2

Interest expense, including amortization

     (8,724     (9,549     825   
                        
     (8,257     (9,003     746   
                        

Income before income taxes

     19,031        13,481        5,550   

State income tax

     (18     (46     28   
                        

Net income

     19,013        13,435        5,578   

Less general partner interest in net income, including incentive distributions (1)

     3,847        2,909        938   
                        

Limited partners’ interest in net income

   $ 15,166      $ 10,526      $ 4,640   
                        

Limited partners’ earnings per unit – basic and diluted (1)

   $ 0.69      $ 0.48      $ 0.21   
                        

Weighted average limited partners’ units outstanding

     22,079        22,079        —     
                        

EBITDA (2)

   $ 35,468      $ 30,619      $ 4,849   
                        

Distributable cash flow (3)

   $ 21,421      $ 22,673      $ (1,252
                        

Volumes (bpd)

      

Pipelines:

      

Affiliates – refined product pipelines

     90,984        98,464        (7,480

Affiliates – intermediate pipelines

     84,201        86,140        (1,939

Affiliates – crude pipelines

     160,648        141,263        19,385   
                        
     335,833        325,867        9,966   

Third parties – refined product pipelines

     51,627        34,844        16,783   
                        
     387,460        360,711        26,749   

Terminals and loading racks:

      

Affiliates

     182,394        186,515        (4,121

Third parties

     42,694        37,902        4,792   
                        
     225,088        224,417        671   
                        

Total for pipelines and terminal assets (bpd)

     612,548        585,128        27,420   
                        

 

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     Six Months Ended
June  30,
    Change
from

2010
 
     2011     2010    
     (In thousands, except per unit data)  

Revenues

      

Pipelines:

      

Affiliates – refined product pipelines

   $ 21,547      $ 23,547      $ (2,000

Affiliates – intermediate pipelines

     9,702        10,756        (1,054

Affiliates – crude pipelines

     18,945        19,133        (188
                        
     50,194        53,436        (3,242

Third parties – refined product pipelines

     21,061        11,859        9,202   
                        
     71,255        65,295        5,960   

Terminals and loading racks:

      

Affiliates

     21,052        17,240        3,812   

Third parties

     3,650        3,644        6   
                        
     24,702        20,884        3,818   
                        

Total revenues

     95,957        86,179        9,778   

Operating costs and expenses

      

Operations

     27,162        26,555        607   

Depreciation and amortization

     15,353        14,801        552   

General and administrative

     2,936        4,476        (1,540
                        
     45,451        45,832        (381
                        

Operating income

     50,506        40,347        10,159   

Equity in earnings of SLC Pipeline

     1,207        1,025        182   

Interest income

     —          5        (5

Interest expense, including amortization

     (17,273     (17,093     (180

Other

     (12     (7     (5
                        
     (16,078     (16,070     (8
                        

Income before income taxes

     34,428        24,277        10,151   

State income tax

     (246     (140     (106
                        

Net income

     34,182        24,137        10,045   

Less general partner interest in net income, including incentive distributions (1)

     7,409        5,555        1,854   
                        

Limited partners’ interest in net income

   $ 26,773      $ 18,582      $ 8,191   
                        

Limited partners’ earnings per unit – basic and diluted (1)

   $ 1.21      $ 0.84      $ 0.37   
                        

Weighted average limited partners’ units outstanding

     22,079        22,079        —     
                        

EBITDA (2)

   $ 67,054      $ 56,166      $ 10,888   
                        

Distributable cash flow (3)

   $ 42,193      $ 42,831      $ (638
                        

Volumes (bpd)

      

Pipelines:

      

Affiliates – refined product pipelines

     84,139        95,937        (11,798

Affiliates – intermediate pipelines

     76,452        82,649        (6,197

Affiliates – crude pipelines

     148,520        138,094        10,426   
                        
     309,111        316,680        (7,569

Third parties – refined product pipelines

     50,086        32,850        17,236   
                        
     359,197        349,530        9,667   

Terminals and loading racks:

      

Affiliates

     170,230        175,218        (4,988

Third parties

     41,532        36,381        5,151   
                        
     211,762        211,599        163   
                        

Total for pipelines and terminal assets (bpd)

     570,959        561,129        9,830   
                        

 

(1) 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.

 

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(2) 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 U.S. generally accepted accounting principles (“GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. 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
June 30,
    Six Months Ended
June 30,
 
     2011      2010     2011      2010  
     (In thousands)  

Net income

   $ 19,013       $ 13,435      $ 34,182       $ 24,137   

Add (subtract):

          

Interest expense

     8,419         8,209        16,678         14,095   

Amortization of discount and deferred debt issuance costs

     305         264        595         458   

Increase in interest expense – change in fair value of interest rate swaps and swap settlement costs

     —           1,076        —           2,540   

Interest income

     —           (2     —           (5

State income tax

     18         46        246         140   

Depreciation and amortization

     7,713         7,591        15,353         14,801   
                                  

EBITDA

   $ 35,468       $ 30,619      $ 67,054       $ 56,166   
                                  

 

(3) 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, and maintenance capital expenditures. 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 is also 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.

 

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Set forth below is our calculation of distributable cash flow.

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011     2010     2011     2010  
     (In thousands)  

Net income

   $ 19,013      $ 13,435      $ 34,182      $ 24,137   

Add (subtract):

        

Depreciation and amortization

     7,713        7,591        15,353        14,801   

Amortization of discount and deferred debt issuance costs

     305        264        595        458   

Increase in interest expense – change in fair value of interest rate swaps and swap settlement costs

     —          1,076        —          2,540   

Equity in excess cash flows over earnings of SLC Pipeline

     308        174        314        352   

Increase (decrease) in deferred revenue

     (4,014     1,414        (5,118     2,521   

Maintenance capital expenditures*

     (1,904     (1,281     (3,133     (1,978
                                

Distributable cash flow

   $ 21,421      $ 22,673      $ 42,193      $ 42,831   
                                

 

* Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations.

 

     June 30,     December 31,  
     2011     2010  
Balance Sheet Data    (In thousands)  

Cash and cash equivalents

   $ 1,402      $ 403   

Working capital deficit

   $ (2,026   $ (7,758

Total assets

   $ 651,151      $ 643,273   

Long-term debt

   $ 518,818      $ 491,648   

Partners’ equity (4)

   $ 99,947      $ 109,372   

 

(4) 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 HFC had occurred while we were not a consolidated variable interest entity of HFC, our acquisition cost in excess of HFC’s historical basis in the transferred assets of $218 million would have been recorded in our financial statements as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.

 

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Results of Operations – Three Months Ended June 30, 2011 Compared with Three Months Ended June 30, 2010

Summary

Net income for the three months ended June 30, 2011 was $19 million, a $5.6 million increase compared to the three months ended June 30, 2010. This increase in overall earnings is due principally to an increase in deferred revenue realized and increased third-party refined product pipeline shipments.

Revenues for the three months ended June 30, 2011 include the recognition of $5.5 million of prior shortfalls billed to shippers in 2010 as they did not meet their minimum volume commitments within the contractual make-up period. This includes the recognition of $2.4 million of shortfalls billed in the third and fourth quarters of 2010 as a result of an amendment to the Alon PTA in June 2011 that limits the carryover term of shortfall credits to the calendar year in which the shortfalls occurred. Revenues of $1.5 million relating to deficiency payments associated with certain guaranteed shipping contracts were deferred during the three months ended June 30, 2011. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels, or when shipping rights expire unused.

Revenues

Total revenues for the three months ended June 30, 2011 were $50.9 million, a $5.5 million increase compared to the three months ended June 30, 2010. This is due principally to a $3.8 million increase in previously deferred revenue realized. Overall pipeline shipments were up 7% from the second quarter of 2010, due mainly to an increase in third-party refined product pipeline shipments.

Revenues from our refined product pipelines were $23.6 million, an increase of $5.1 million compared to the three months ended June 30, 2010. This increase is due principally to a $3.6 million increase in previously deferred revenue realized. Volumes shipped on our refined product pipelines averaged 142.6 thousand barrels per day (“mbpd“) compared to 133.3 mbpd for the same period last year.

Revenues from our intermediate pipelines were $5.1 million, an increase of $0.1 million compared to the three months ended June 30, 2010. This reflects a $0.2 million increase in previously deferred revenue realized, partially offset by a decrease in intermediate pipeline shipments. Volumes shipped on our intermediate pipelines averaged 84.2 mbpd compared to 86.1 mbpd for the same period last year.

Revenues from our crude pipelines were $9.6 million, a decrease of $0.1 million compared to the three months ended June 30, 2010. Volumes shipped on our crude pipelines averaged 160.6 mbpd compared to 141.3 mbpd for the same period last year. Although shipments were up, we did not realize higher revenues in the current year due to the receipt of higher minimum revenue commitment fees from HFC in 2010.

Revenues from terminal, tankage and loading rack fees were $12.7 million, an increase of $0.4 million compared to the three months ended June 30, 2010. Refined products terminalled in our facilities increased to an average of 225.1 mbpd compared to 224.4 mbpd for the same period last year.

Operations Expense

Operations expense for the three months ended June 30, 2011 increased by $0.9 million compared to the three months ended June 30, 2010. This increase is due principally to increased maintenance costs during the current year second quarter.

Depreciation and Amortization

Depreciation and amortization for the three months ended June 30, 2011 increased by $0.1 million compared to the three months ended June 30, 2010.

 

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General and Administrative

General and administrative costs for the three months ended June 30, 2011 decreased by $0.3 million compared to the three months ended June 30, 2010 due to lower professional fees during the current year.

Equity in Earnings of SLC Pipeline

Our equity in earnings of the SLC Pipeline was $0.5 million for the three months ended June 30, 2011 and 2010.

Interest Expense

Interest expense for the three months ended June 30, 2011 totaled $8.7 million, a decrease of $0.8 million compared to the three months ended June 30, 2010. Interest costs for the three months ended June 30, 2010 include $1.1 million in costs attributable to the partial settlement of an interest rate swap. This was partially offset by interest on increased credit agreement borrowings during the current year. Our aggregate effective interest rate was 6.7% for the three months ended June 30, 2011 compared to 7.7% for the same period of 2010.

State Income Tax

We recorded state income taxes of $18,000 and $46,000 for the three months ended June 30, 2011 and 2010, respectively, which are solely attributable to the Texas margin tax.

Results of Operations – Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010

Summary

Net income for the six months ended June 30, 2011 was $34.2 million, a $10 million increase compared to the six months ended June 30, 2010. This increase in overall earnings is due principally to an overall increase in pipeline shipments, earnings attributable to our March 2010 asset acquisitions and an increase in previously deferred revenue realized.

Revenues for the six months ended June 30, 2011 include the recognition of $9.1 million of prior shortfalls billed to shippers in 2010. Revenues of $3.9 million relating to deficiency payments associated with certain guaranteed shipping contracts were deferred during the six months ended June 30, 2011. Such deferred revenue will be recognized in earnings either as payment for shipments in excess of guaranteed levels, or when shipping rights expire unused.

Revenues

Total revenues for the six months ended June 30, 2011 were $96 million, a $9.8 million increase compared to the six months ended June 30, 2010. This is due principally to increased pipeline shipments, revenues attributable to our March 2010 asset acquisitions and a $4.9 million increase in previously deferred revenue realized. Overall pipeline shipments were up 3% from the six months ended June 30, 2010, due to an increase in third-party refined product pipeline shipments that was partially offset by decreased affiliate pipeline shipments.

Related-party pipeline and throughput volumes were down during the current year-to-date period as a result of downtime at HFC’s Navajo refinery following a plant-wide power outage in late January 2011 and the subsequent delay in restoring production to planned levels.

Revenues from our refined product pipelines were $42.6 million, an increase of $7.2 million compared to the six months ended June 30, 2010. This is due to a $5.3 million increase in previously deferred revenue realized and an increase in third-party refined product pipeline shipments. Volumes shipped on our refined product pipelines averaged 134.2 mbpd compared to 128.8 mbpd for the same period last year.

 

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Revenues from our intermediate pipelines were $9.7 million, a decrease of $1.1 million compared to the six months ended June 30, 2010. This reflects a $0.4 million decrease in previously deferred revenue realized and a decrease in intermediate pipeline shipments. Shipments on our intermediate pipelines decreased to an average of 76.5 mbpd compared to 82.6 mbpd for the same period last year.

Revenues from our crude pipelines were $18.9 million, a decrease of $0.2 million compared to the six months ended June 30, 2010. Volumes on our crude pipelines averaged 148.5 mbpd compared to 138.1 mbpd for the same period last year. Although shipments were up, we did not realize higher revenues in the current year due to the receipt of higher minimum revenue commitment fees from HFC in 2010.

Revenues from terminal, tankage and loading rack fees were $24.7 million, an increase of $3.8 million compared to the six months ended June 30, 2010. This increase is due primarily to revenues attributable to our Tulsa storage and rack facilities acquired from HFC in March 2010. Refined products terminalled in our facilities increased to an average of 211.8 mbpd compared to 211.6 mbpd for the same period last year.

Operations Expense

Operations expense for the six months ended June 30, 2011 increased by $0.6 million compared to the six months ended June 30, 2010. This increase is due principally to increased maintenance costs during the current year-to-date period.

Depreciation and Amortization

Depreciation and amortization for the six months ended June 30, 2011 increased by $0.6 million compared to the six months ended June 30, 2010. This was due to increased depreciation attributable to our March 2010 asset acquisitions from HFC and capital projects.

General and Administrative

General and administrative costs for the six months ended June 30, 2011 decreased by $1.5 million compared to the six months ended June 30, 2010, which included higher professional fees and costs as a result of our March 2010 asset acquisitions from HFC.

Equity in Earnings of SLC Pipeline

Our equity in earnings of the SLC Pipeline was $1.2 million and $1 million for the six months ended June 30, 2011 and 2010, respectively.

Interest Expense

Interest expense for the six months ended June 30, 2011 totaled $17.3 million, an increase of $0.2 million compared to the six months ended June 30, 2010. This increase reflects interest on increased debt levels during the current year, partially offset by prior year costs of $1.1 million that relate to the partial settlement of an interest rate swap. Excluding the effects of fair value adjustments to this swap in 2010, our aggregate effective interest rate was 6.7% for the six months ended June 30, 2011 compared to 6.8% for 2010.

State Income Tax

We recorded state income taxes of $246,000 and $140,000 for the six months ended June 30, 2011 and 2010, respectively, which are solely attributable to the Texas margin tax.

 

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LIQUIDITY AND CAPITAL RESOURCES

Overview

During the six months ended June 30, 2011, we received advances totaling $64 million and repaid $37 million, resulting in net borrowings of $27 million under our $275 million senior secured revolving credit facility (the “Credit Agreement”) and an outstanding balance of $186 million at June 30, 2011.

The Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $30 million sub-limit.

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 HFC 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 and May 2011 we paid regular quarterly cash distributions of $0.845 and $0.855, respectively, on all units in an aggregate amount of $44.9 million. Included in these distributions were $6.4 million of incentive distribution payments to the general partner.

Cash and cash equivalents increased by $1 million during the six months ended June 30, 2011. The cash flows provided by operating activities of $46.3 million exceeded the combined cash flows used for investing and financing activities of $22.9 million and $22.4 million, respectively. Working capital increased by $5.7 million to $(2.0) million during the six months ended June 30, 2011.

Cash Flows - Operating Activities

Cash flows from operating activities increased by $1.1 million from $45.2 million for the six months ended June 30, 2010 to $46.3 million for the six months ended June 30, 2011. This increase is due principally to $3.1 million in additional cash collections from our customers combined with a decrease in payments related to operating expenses. These factors were partially offset by increased interest payments.

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. We billed $6.6 million during the six months ended June 30, 2010 related to shortfalls that subsequently expired without recapture and were recognized as revenue during the six months ended June 30, 2011. We recognized an additional $2.4 million related to shortfalls billed in the third and fourth quarters of 2010 as a result of an amendment to the Alon PTA in June 2011 that limits the carryover term of credits attributable to such shortfall billings to the calendar year end in which the shortfalls occurred. Another $1.5 million is included in our accounts receivable at June 30, 2011 related to shortfalls that occurred during the second quarter of 2011.

 

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Cash Flows - Investing Activities

Cash flows used for investing activities decreased by $20.6 million from $43.5 million for the six months ended June 30, 2010 to $22.9 million for the six months ended June 30, 2011. During the six months ended June 30, 2011 and 2010, we invested $22.9 million and $4.5 million in additions to properties and equipment, respectively. Additionally in March 2010, we acquired storage assets from HFC for $39 million.

Cash Flows - Financing Activities

Cash flows used for financing activities were $22.4 million compared to $1.4 million for the six months ended June 30, 2010, an increase of $21 million. During the six months ended June 30, 2011, we received $64 million and repaid $37 million in advances under the Credit Agreement, we paid $44.9 million in regular quarterly cash distributions to our general and limited partners, paid $3.1 million in financing costs to amend our previous credit agreement and paid $1.4 million for the purchase of common units for recipients of our incentive grants. During the six months ended June 30, 2010, we received $39 million and repaid $90 million in advances under the Credit Agreement. Additionally, we received $147.5 million in net proceeds and incurred $0.4 million in financing costs upon the issuance of the 8.25% Senior Notes. For the six months ended June 30, 2010, we paid $41.3 million in regular quarterly cash distributions to our general and limited partners, paid $54 million in excess of HFC’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 incentive grants.

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 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 2011 capital budget is comprised of $5.8 million for maintenance capital expenditures and $20.1 million for expansion capital expenditures.

We are currently constructing five interconnecting pipelines between HFC’s Tulsa east and west refining facilities. The project is expected to cost approximately $35 million with completion in the late summer of 2011. We are finalizing terms under a long-term agreement with HFC 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, HFC will reimburse us for the cost of the pipelines.

Additionally, we have two expansion projects to provide 60,000 bpd of additional crude pipeline take-away capacity resulting from increased Delaware Basin drilling activity in southeast New Mexico.

The first project will increase one of our existing crude oil trunk lines from 35,000 bpd to 60,000 bpd. This 35-mile pipeline transports crude oil from our gathering system in southeast New Mexico to HFC’s New Mexico refining facilities. The scope of the project includes the replacement of 5 miles of existing pipe with larger diameter pipe and the addition of a higher horsepower pump. Work will commence shortly and is expected to be completed during the first half of 2012.

The second project will consist of the reactivation and conversion to crude oil service a 70-mile, 8-inch petroleum products pipeline owned by us. Once in service, this pipeline would be capable of transporting

 

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up to 35,000 bpd of crude oil from rapidly developing Delaware Basin production in the Carlsbad, New Mexico area to either a third party common carrier pipeline station for transport to major crude oil markets or to HFC’s New Mexico refining facilities. The scope of this project is in the process of being finalized. It is anticipated that this project, subject to receipt of acceptable shipper support and board approval, could also be completed during the first half of 2012.

We have an option agreement with HFC, granting us an option to purchase HFC’s 75% equity interest in UNEV Pipeline, LLC (“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 HFC’s equity interest in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to HFC’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 construction cost of the pipeline project including terminals is expected to be approximately $385 million. This includes the construction of ethanol blending and storage facilities at the Cedar City terminal. HFC’s share of this estimated cost is $289 million and is exclusive of the 7% per annum interest cost under our option to purchase HFC’s 75% interest in the UNEV Pipeline. The pipeline is in the final construction phase and is expected to be mechanically complete later this year.

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 Credit Agreement, or a combination thereof. With volatility and uncertainty at times in the credit and equity markets, there may be limits on our ability to issue new debt or equity financing. Additionally, due to pricing movements in the debt and equity markets, we may not be able to issue new debt and equity securities at acceptable pricing. Without additional capital beyond amounts available under the Credit Agreement, our ability to fund some of these capital projects may be limited, especially the UNEV Pipeline. 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

We have a $275 million Credit Agreement that is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to a $30 million sub-limit. In February 2011, we amended our previous credit agreement (expiring in August 2011), extending the expiration date and slightly reducing the size of the credit facility from $300 million to $275 million. The size was reduced based on management’s review of past and forecasted utilization of the facility. The Credit Agreement expires in February 2016; however, in the event that the 6.25% Senior Notes are not repurchased, refinanced, extended or repaid prior to September 1, 2014, the Credit Agreement shall expire on that date.

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 material, 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.

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 1.00% to 2.00%) or (b) at a rate equal to the London Interbank Offered Rate (“LIBOR“) plus an applicable margin (ranging from 2.00% to 3.00%). 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). We incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.375% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.

 

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The Credit Agreement imposes certain requirements on us including: a prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire other companies, change the nature of our business, enter a merger or consolidation, or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio, total debt to EBITDA ratio and senior 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.

Senior Notes

The 6.25% Senior Notes and 8.25% Senior Notes (collectively, the “Senior Notes”) are unsecured and impose certain restrictive covenants which we are subject to and currently in compliance with, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights under the Senior Notes.

Indebtedness under the Senior Notes is recourse to HEP Logistics Holdings, L.P., our general partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its investment in us, are not significant.

The carrying amounts of our long-term debt are as follows:

 

     June 30,
2011
    December 31,
2010
 
     (In thousands)  

Credit Agreement

   $ 186,000      $ 159,000   

6.25% Senior Notes

    

Principal

     185,000        185,000   

Unamortized discount

     (1,394     (1,584

Unamortized premium – dedesignated fair value hedge

     1,271        1,444   
                
     184,877        184,860   
                

8.25% Senior Notes

    

Principal

     150,000        150,000   

Unamortized discount

     (2,059     (2,212
                
     147,941        147,788   
                

Total long-term debt

   $ 518,818      $ 491,648   
                

See “Risk Management” for a discussion of our interest rate swap.

Contractual Obligations

During the six months ended June 30, 2011, we had net borrowings of $27 million resulting in $186 million of borrowings outstanding under the Credit Agreement at June 30, 2011.

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 moderate in recent years and did not have a material impact on our results of operations for the six months ended June 30, 2011 and 2010. Historically, the PPI has increased an average of 3% annually over the past 5 calendar years. However, the June 30, 2011 PPI increased at a rate of 7% on a year-over-year basis.

 

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The 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. Certain of these contracts have provisions that limit the level of annual PPI percentage rate increases. Although the recent PPI increase may not be indicative of additional increases to be realized in the future, a significant and prolonged period of inflation could adversely affect our cash flows and results of operations if costs increase at a rate greater than the fees we charge our shippers.

Environmental Matters

Our operation of pipelines, terminals, and associated facilities in connection with the transportation and storage 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.

Under the Omnibus Agreement, HFC 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 HFC’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, HFC’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. HFC’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 HFC ETA and HFC PTTA, HFC will indemnify us for environmental liabilities arising from our pre-ownership operations of the Tulsa west loading rack facilities acquired from HFC 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 HFC in March 2010. Additionally, HFC agreed to indemnify us for any liabilities arising from HFC’s operation of the loading racks under the HFC 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 HFC. Certain of these projects were underway prior to our purchase and represent liabilities of HFC as the obligation for future remediation activities was retained by HFC. At June 30,

 

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2011, we have an accrual of $0.2 million that relates to environmental clean-up projects for which we have assumed liability. The remaining projects, including assessment and monitoring activities, are covered under the HFC environmental indemnification discussed above and represent liabilities of HFC.

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. 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, 2010. 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 2011. 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.

RISK MANAGEMENT

We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.

As of June 30, 2011, 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 2.50%, which equals an effective interest rate of 6.24% as of June 30, 2011. This swap contract matures in February 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 $155 million of our 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 $155 million of our 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.

 

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Additional information on our interest rate swap is as follows:

 

Derivative Instrument

 

Balance Sheet

Location

  Fair Value    

Location of Offsetting
Balance

  Offsetting
Amount
 
    (In thousands)  

June 30, 2011

       

Interest rate swap designated as cash flow hedging instrument:

     

Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)

 

Other long-term liabilities

  $ 8,472     

Accumulated other comprehensive loss

  $ 8,472   
                   

December 31, 2010

       

Interest rate swap designated as cash flow hedging instrument:

     

Variable-to-fixed interest rate swap contract ($155 million of LIBOR based debt interest)

 

Other long-term liabilities

  $ 10,026     

Accumulated other comprehensive loss

  $ 10,026   
                   

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 commitments 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 respective commitment.

The market risk inherent in our debt positions is the potential change arising from increases or decreases in interest rates as discussed below.

At June 30, 2011, we had an outstanding principal balance on our 6.25% Senior Notes and 8.25% Senior Notes of $185 million and $150 million, respectively. A change in interest rates would generally affect the fair value of the Senior Notes, but not our earnings or cash flows. At June 30, 2011, the fair value of our 6.25% Senior Notes and 8.25% Senior Notes were $184.1 million and $159.4 million, respectively. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6.25% Senior Notes and 8.25% Senior Notes at June 30, 2011 would result in a change of approximately $4 million and $6 million, respectively, in the fair value of the underlying notes.

For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At June 30, 2011, borrowings outstanding under the Credit Agreement were $186 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 6.24%.

At June 30, 2011, our cash and cash equivalents included highly liquid investments with a maturity of three months or less at the time of purchase. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our investment portfolio.

Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

We have a risk management oversight committee that is made up of members from our senior management. This committee monitors our risk environment and provides direction for activities to mitigate, to an acceptable level, identified risks that may adversely affect the achievement of our goals.

 

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Item 3. Quantitative and Qualitative Disclosures About Market Risks

Market risk is the risk of loss arising from adverse changes in market rates and prices. See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of market risk exposures that we have with respect to our cash and cash equivalents and long-term debt. We utilize derivative instruments to hedge our interest rate exposure, also discussed under “Risk Management.”

Since we do not own products shipped on our pipelines or terminalled at our terminal facilities, we do not have market risks associated with commodity prices.

 

Item 4. Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2011.

(b) Changes in internal control over financial reporting

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

 

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PART II. OTHER INFORMATION

 

Item 1. Legal Proceedings

We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.

 

Item 6. Exhibits

The Exhibit Index on page 42 of this Quarterly Report on Form 10-Q lists the exhibits that are filed or furnished, as applicable, as part of the Quarterly Report on Form 10-Q.

 

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HOLLY ENERGY PARTNERS, L.P.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

   

HOLLY ENERGY PARTNERS, L.P.

    (Registrant)
   

By: HEP LOGISTICS HOLDINGS, L.P.

its General Partner

   

By: HOLLY LOGISTIC SERVICES, L.L.C.

its General Partner

Date:   August 1, 2011  

/s/ Douglas S. Aron

    Douglas S. Aron
    Executive Vice President and
    Chief Financial Officer
    (Principal Financial Officer)
   

/s/ Scott C. Surplus

    Scott C. Surplus
    Vice President and Controller
    (Principal Accounting Officer)

 

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Exhibit Index

 

Exhibit
Number

 

Description

    3.1   Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Holly Logistic Services, L.L.C., dated April 27, 2011 (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K Current Report dated May 3, 2011, File No. 1-32225).
  10.1+   First Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated January 25, 2005
  10.2+   Second Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated June 29, 2007
  10.3+   Third Letter Agreement with respect to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated April 1, 2011
  10.4+   First Amendment of Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated September 1, 2008
  10.5+   Second Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated March 1, 2011
  10.6+   Third Amendment to Pipelines and Terminals Agreement between Holly Energy Partners, L.P. and ALON USA, LP, dated June 6, 2011
  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.
101**   The following financial information from Holly Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Partners’ Equity, and (v) Notes to Consolidated Financial Statements (tagged as blocks of text).

 

+ Filed herewith.
++ Furnished herewith.
** Furnished electronically herewith.

 

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