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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2008
Commission File Number 1-32225
HOLLY ENERGY PARTNERS, L.P.
Formed under the laws of the State of Delaware
I.R.S. Employer Identification No. 20-0833098
100 Crescent Court, Suite 1600
Dallas, Texas 75201-6915
Telephone Number: (214) 871-3555
Securities registered pursuant to Section 12(b) of the Act:
Common Limited Partner Units
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in part III of this Form 10-K
or any amendments to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
The aggregate market value of common limited partner units held by non-affiliates of the registrant
was approximately $352 million on June 30, 2008, based on the last sales price as quoted on the New
York Stock Exchange.
The number of the registrants outstanding common limited partners units at February 6, 2009 was
8,390,000.
DOCUMENTS INCORPORATED BY REFERENCE: None
PART I
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K 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-K, including, but not limited to, those under Business, Risk Factors and
Properties in Items 1, 1A and 2 and Managements Discussion and Analysis of Financial Condition
and Results of Operations in Item 7, are forward-looking statements. These statements are based
on managements beliefs and assumptions 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 believe that the expectations reflected in these forward-looking
statements are reasonable, we cannot assure you that our expectations will prove to be correct.
Therefore, actual outcomes and results could differ materially from what is expressed, implied or
forecast in these statements. Any differences could be caused by a number of factors including,
but not limited to:
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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; |
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The economic viability of Holly Corporation, Alon USA, Inc. and our other customers; |
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The demand for refined petroleum products in markets we serve; |
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Our ability to successfully purchase and integrate additional operations in the future; |
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Our ability to complete previously announced pending or contemplated acquisitions; |
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The availability and cost of additional debt and equity financing; |
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The possibility of reductions in production or shutdowns at refineries utilizing our
pipeline and terminal facilities; |
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The effects of current and future government regulations and policies; |
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Our operational efficiency in carrying out routine operations and capital construction
projects; |
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The possibility of terrorist attacks and the consequences of any such attacks; |
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General economic conditions; and |
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Other financial, operations and legal risks and uncertainties detailed from time to time
in our Securities and Exchange Commission filings. |
Cautionary statements identifying important factors that could cause actual results to differ
materially from our expectations are set forth in this Form 10-K, including without limitation, in
conjunction with the forward-looking statements included in the Form 10-K 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 this Form 10-K under Risk Factors in Item 1A. All
forward-looking statements included in this Form 10-K 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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INDEX TO DEFINED TERMS AND NAMES
The following terms and names that appear in this form 10-K are defined on the following pages:
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Alon |
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5 |
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Alon PTA |
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5 |
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ARB |
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58 |
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Big Spring Refinery |
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5 |
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BP |
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15 |
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bpd |
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6 |
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Credit Agreement |
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10 |
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Crude Pipelines and Tankage Assets |
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5 |
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Distributable cash flow |
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41 |
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DOT |
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10 |
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EBITDA |
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41 |
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EITF |
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58 |
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Expansion capital expenditures |
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8 |
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FASB |
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58 |
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FERC |
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6 |
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Fixed Rate Swap |
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59 |
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FSP |
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58 |
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GAAP |
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41 |
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HEP |
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5 |
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HLS |
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5 |
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Holly |
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5 |
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Holly CPTA |
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5 |
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Holly IPA |
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5 |
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Holly PTA |
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5 |
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Intermediate Pipelines |
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5 |
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LPG |
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6 |
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Maintenance capital expenditures |
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42 |
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mbbls |
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31 |
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mbpd |
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50 |
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Mid-America |
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31 |
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MLP |
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58 |
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NPL |
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5 |
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NuStar |
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35 |
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Omnibus Agreement |
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6 |
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Plains |
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9 |
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PPI |
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6 |
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Rio Grande |
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6 |
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SEC |
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5 |
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SFAS |
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58 |
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Sinclair |
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36 |
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SLC Pipeline |
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9 |
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ULSD |
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49 |
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UNEV Pipeline |
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9 |
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Valero |
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35 |
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Variable Rate Swap |
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59 |
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Terms used in the financial statements and footnotes are as defined therein.
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Item 1. Business
OVERVIEW
Holly Energy Partners, L.P. (HEP) is a Delaware limited partnership formed by Holly
Corporation and is the successor to Navajo Pipeline Co., L.P. (Predecessor) (NPL). We operate a
system of refined product and crude oil pipelines, storage tanks and distribution terminals
primarily in west Texas, New Mexico, Utah and Arizona. We maintain our principal corporate offices
at 100 Crescent Court, Suite 1600, Dallas, Texas 75201-6915. Our telephone number is 214-871-3555
and our internet website address is www.hollyenergy.com. The information contained on our website
does not constitute part of this Annual Report on Form 10-K. A copy of this Annual Report on Form
10-K will be provided without charge upon written request to the Vice President, Investor Relations
at the above address. A direct link to our filings at the U.S. Securities and Exchange Commission
(SEC) website is available on our website on the Investors page. Additionally available on our
website are copies of our Corporate Governance Guidelines, Audit Committee Charter, Compensation
Committee Charter, and Code of Business Conduct and Ethics, all of which will be provided without
charge upon written request to the Vice President, Investor Relations at the above address. In
this document, the words we, our, ours and us refer to HEP and its consolidated
subsidiaries or to HEP or an individual subsidiary and not to any other person. Holly refers to
Holly Corporation and its subsidiaries, other than HEP and its subsidiaries and other than Holly
Logistic Services, L.L.C. (HLS), a subsidiary of Holly Corporation that is the general partner of
the general partner of HEP and manages HEP.
We generate revenues by charging tariffs for transporting refined product and crude oil through our
pipelines and by charging fees for terminalling refined products and other hydrocarbons, and
storing and providing other services at our terminals. We do not take ownership of products that
we transport or terminal; therefore, we are not directly exposed to changes in commodity prices.
We serve Hollys refineries in New Mexico and Utah under three 15-year pipeline, terminal and
tankage agreements with Holly. One of these agreements relates to the pipelines and terminals
contributed by Holly to us at the time of our initial public offering in 2004 and expires in 2019
(Holly PTA). Our second agreement with Holly relates to the intermediate pipelines acquired from
Holly in July 2005 (Intermediate Pipelines) that serve Hollys Lovington and Artesia, New Mexico
refinery facilities (collectively, the Navajo Refinery) and expires in 2020 (Holly IPA). Our
third agreement, relates to the crude pipelines and tankage assets acquired from Holly in February
2008 (the Crude Pipelines and Tankage Assets) and expires in 2023 (Holly CPTA). We also serve
the Alon USA, Inc. (Alon) Big Spring, Texas refinery (Big Spring Refinery) under the Alon
pipelines and terminals agreement expiring in 2020 (Alon PTA). The substantial majority of our
business is devoted to providing transportation and terminalling services to Holly. We operate our
business as one business segment.
Our assets include:
Pipelines:
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approximately 820 miles of refined product pipelines, including 340 miles of leased
pipelines, that transport gasoline, diesel, and jet fuel principally from Hollys Navajo
Refinery in New Mexico to its customers in the metropolitan and rural areas of Texas, New
Mexico, Arizona, Colorado, Utah and northern Mexico; |
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approximately 510 miles of refined product pipelines that transport refined products
from Alons Big Spring Refinery in Texas to its customers in Texas and Oklahoma; |
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two parallel 65-mile pipelines that transport intermediate feedstocks and crude oil from
Hollys Lovington, New Mexico refinery facilities to Hollys Artesia, New Mexico refinery
facilities; |
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approximately 860 miles of crude oil trunk, gathering and connection pipelines located
in west Texas and New Mexico that deliver crude oil to Hollys Navajo Refinery; |
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approximately 10 miles of crude oil and refined product pipelines that support Hollys
Woods Cross Refinery near Salt Lake City, Utah; and |
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a 70% interest in Rio Grande Pipeline Company (Rio Grande), a joint venture that owns
a 249-mile refined product pipeline that transports liquid petroleum gases (LPG) from
west Texas to the Texas/Mexico border near El Paso for further transport into northern
Mexico. |
Refined Product Terminals and Refinery Tankage:
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four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New
Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,000,000 barrels,
that are integrated with our refined product pipeline system that serves Hollys Navajo
Refinery; |
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three refined product terminals (two of which are 50% owned), located in Burley and
Boise, Idaho and Spokane, Washington, with an aggregate capacity of approximately 500,000
barrels, that serve third-party common carrier pipelines; |
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one refined product terminal near Mountain Home, Idaho with a capacity of 120,000
barrels, that serves a nearby United States Air Force Base; |
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two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank
farm in Orla, Texas with aggregate capacity of 480,000 barrels, that are integrated with
our refined product pipelines that serve Alons Big Spring Refinery; |
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two refined product truck loading racks, one located within Hollys Navajo Refinery that
is permitted to load over 40,000 barrels per day (bpd) of light refined products, and one
located within Hollys Woods Cross Refinery, that is permitted to load over 25,000 bpd of
light refined products; |
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a Roswell, New Mexico jet fuel terminal leased through September 2011; and |
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on-site crude oil tankage at Hollys Navajo and Woods Cross Refineries having an
aggregate storage capacity of approximately 600,000 barrels. |
Holly Crude Pipelines and Tankage Transaction
On February 29, 2008, we acquired the Crude Pipelines and Tankage Assets from Holly for $180.0
million that consist of crude oil trunk lines that deliver crude oil to Hollys Navajo Refinery in
southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico,
on-site crude tankage located within the Navajo and Woods Cross refinery complexes, a jet fuel
products pipeline between Artesia and Roswell, New Mexico, a leased jet fuel terminal in Roswell,
New Mexico and crude oil and refined product pipelines that support Hollys Woods Cross Refinery.
The consideration paid consisted of $171.0 million in cash and 217,497 of our common units having a
fair value of $9.0 million. We financed the $171.0 million cash portion of the consideration
through borrowings under our senior secured revolving credit agreement expiring August 2011.
In connection with this transaction, we entered into a 15-year crude pipelines and tankage
agreement with Holly. Under the Holly CPTA, Holly agreed to transport and store volumes of crude
oil on the crude pipelines and tankage facilities that at the agreed rates will result in minimum
annual payments to us of $26.8 million. These minimum annual payments or revenue will be adjusted
each year at a rate equal to the percentage change in the Producer Price Index (PPI) but will not
decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates will
generally be increased annually by the
percentage change in the Federal Energy Regulatory Commission (FERC) Oil Pipeline Index. The
FERC index is the change in the PPI plus a FERC adjustment factor which is reviewed periodically.
Additionally, Holly amended our omnibus agreement (the Omnibus Agreement) to provide $7.5 million
of indemnification for a period of up to fifteen years for environmental noncompliance and
remediation liabilities
associated with the Crude Pipelines and Tankage Assets that occurred or
existed prior to our acquisition.
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Agreements with Holly and Alon
In addition to the Holly CPTA, the Holly PTA relates to the pipelines and terminals contributed by
Holly to us at the time of our initial public offering in 2004 and expires in 2019, and the Holly
IPA that relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in
2020. Under these agreements, Holly has agreed to transport and store volumes of refined product
on our pipelines and terminal facilities that result in minimum annual payments to us. These
minimum annual payments or revenues will be adjusted each year at a percentage change equal to the
change in the PPI but will not decrease as a result of a decrease in the PPI. Under the Holly PTA
and Holly IPA, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to the
percentage change in the PPI, but generally will not decrease as a result of a decrease in the PPI.
We also have a 15-year 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 results in a minimum level of annual revenue. Under the Alon PTA, the agreed
upon tariff rates are increased or decreased annually at a rate equal to the percentage change in
PPI, but not below the initial tariff rate.
As of December 31, 2008, contractual minimums under our long-term service agreements are as
follows:
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Minimum Annualized |
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Commitment |
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Agreement |
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(In millions) |
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Year of Maturity |
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Contract Type |
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Holly PTA |
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$ |
41.2 |
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2019 |
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Minimum revenue commitment |
Holly IPA |
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13.3 |
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2020 |
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Minimum revenue commitment |
Holly CPTA |
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26.8 |
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2023 |
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Minimum revenue commitment |
Alon PTA |
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22.0 |
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2020 |
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Minimum volume commitment |
Alon capacity lease |
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6.8 |
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Various |
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Capacity lease |
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Total |
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$ |
110.1 |
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We depend on our agreements with Holly and Alon for the majority of our revenues. A significant
reduction in revenues under these agreements would have a material adverse effect on our results of
operations.
Furthermore, if new laws or regulations that affect terminals or pipelines are enacted that require
us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we
will have the right after we have made efforts to mitigate their effects to negotiate a monthly
surcharge on Holly for the use of the terminals or to file for an increased tariff rate for use of
the pipelines to cover Hollys pro rata portion of the cost of complying with these laws or
regulations including a reasonable rate of return. In such instances, we will negotiate in good
faith with Holly to agree on the level of the monthly surcharge or increased tariff rate.
Under certain circumstances, certain of Hollys obligations under these agreements may be
temporarily suspended or terminated.
Omnibus Agreement
Under certain provisions of the Omnibus Agreement that we entered with Holly in July 2004 and
expires in 2019, we pay Holly an annual administrative fee for the provision by Holly or its
affiliates of various
general and administrative services to us. Initially, this fee was $2.0 million for each of the
three years following the closing of our initial public offering. Effective March 1, 2008, the
annual fee was increased to $2.3 million to cover additional general and administrative services
attributable to the operations of our Crude Pipelines and Tankage Assets. This fee includes
expenses incurred by Holly and its affiliates to perform centralized corporate functions, such as
executive management, legal, accounting, treasury,
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information technology and other corporate
services, including the administration of employee benefit plans. This fee does not include the
salaries of pipeline and terminal personnel or the cost of their employee benefits, such as 401(k),
pension and health insurance benefits, which are separately charged to us by Holly. We also
reimburse Holly and its affiliates for direct expenses they incur on our behalf. In addition, we
also pay for our own direct general and administrative costs, including costs relating to operating
as a separate publicly held entity, such as costs for preparation of partners K-1 tax information,
SEC filings, investor relations, directors compensation, directors and officers insurance and
registrar and transfer agent fees.
Under the Omnibus Agreement, Holly has also 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 Omnibus Agreement
provides environmental indemnification of up to $15.0 million through 2014 for the assets
transferred to us at the time of our initial public offering in 2004 and up to $2.5 million through
2015 for the Intermediate Pipelines acquired in July 2005. In February 2008, Holly amended the
Omnibus Agreement to provide an additional $7.5 million of indemnification through 2023 for
environmental noncompliance and remediation liabilities specific to the Crude Pipelines and Tankage
Assets.
Alon
In connection with our purchase of certain refined products pipelines, tankage and terminals from
Alon in 2005, we entered into a 15-year pipelines and terminals agreement with Alon to transport
and terminal light refined products for Alons refinery in Big Spring, Texas. Under the Alon PTA,
Alon agreed to transport on our pipelines and throughput in our terminals a volume of refined
products that would result in minimum revenue levels each year that will change annually based on
changes in the PPI, but will not decrease below the initial $20.2 million annual amount. Following
the March 1, 2008 PPI adjustment, Alons total minimum commitment for the twelve months ending
February 28, 2009 is $22.0 million.
Alons minimum volume commitment was calculated based on 90% of Alons then recent usage of these
pipelines and terminals taking into account an expansion of Alons Big Spring Refinery completed in
February 2005. At revenue levels above 105% of the base revenue amount, as adjusted each year for
changes in the PPI, Alon will receive an annual 50% discount on incremental revenues. Alons
obligations under the Alon PTA may be reduced or suspended under certain circumstances.
Additionally, we entered into an environmental agreement expiring in 2015 with Alon with respect to
pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired
from Alon, whereby Alon will indemnify us subject to a $100,000 deductible and a $20.0 million
maximum liability cap.
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 have consisted of, and are expected to continue to consist
of, maintenance capital expenditures and expansion capital expenditures. Maintenance capital
expenditures represent capital expenditures to replace partially or fully depreciated assets to
maintain the operating capacity of existing assets. Maintenance capital expenditures include
expenditures required to maintain equipment reliability, tankage and pipeline integrity, and safety
and to address environmental regulations. Expansion capital expenditures represent capital
expenditures to expand the operating capacity of existing or new assets, whether through
construction or acquisition. Expansion capital expenditures include expenditures to acquire
assets, to grow our business and to expand existing facilities, such as projects that increase
throughput capacity on our pipelines and in our terminals. 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 to a
particular capital project may be expended over a period in excess of a year, depending on the time
required to complete
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the project. Therefore, our planned capital expenditures for a given year
consist of expenditures approved for capital projects included in the current years capital budget
as well as, in certain cases, expenditures approved for capital projects in capital budgets for
prior years. The 2009 capital budget is comprised of $3.7 million for maintenance capital
expenditures and $2.2 million for expansion capital expenditures. Additionally, capital
expenditures planned in 2009 include approximately $43.0 million for capital projects approved in
prior years, most of which relate to the expansion of the South System and the joint venture with
Plains All American Pipeline, L.P. (Plains) discussed below.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we
have agreed to expand our pipeline system between Artesia, New Mexico and El Paso, Texas (the
South System). The expansion of the South System includes replacing 85 miles of 8-inch pipe with
12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso Terminal, improving
existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and
making related modifications. The cost of this project is estimated to be $48.3 million. We
expect to complete the majority of this project in early 2009.
In November 2007, we executed a definitive agreement with Plains to acquire a 25% joint venture
interest in a new 95-mile intrastate pipeline system now under construction by Plains for the
shipment of up to 120,000 bpd of crude oil into the Salt Lake City area (the SLC Pipeline).
Under the agreement, the SLC Pipeline will be owned by a joint venture company that will be owned
75% by Plains and 25% by us. We expect to purchase our 25% interest in the joint venture in March
2009 when the SLC Pipeline is expected to become fully operational. The SLC Pipeline will allow
various refiners in the Salt Lake City area, including Hollys Woods Cross refinery, to ship crude
oil into the Salt Lake City area from the Utah terminus of the Frontier Pipeline as well as crude
oil from Wyoming and Utah that is currently flowing on Plains Rocky Mountain Pipeline. The total
cost of our investment in the SLC Pipeline is expected to be $28.0 million, including a $2.5
million finders fee that is payable to Holly upon the closing of our investment in the SLC
Pipeline.
On January 31, 2008, we entered into an option agreement with Holly, granting us an option to
purchase all of Hollys equity interests in a joint venture pipeline currently under construction.
The pipeline will be capable of transporting refined petroleum products from Salt Lake City, Utah
to Las Vegas, Nevada (the UNEV Pipeline). Holly owns 75% of the equity interests in the UNEV
Pipeline. Under this agreement, we have an option to purchase Hollys equity interests in the UNEV
Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at
a purchase price equal to Hollys 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 total cost of the pipeline project including terminals is expected
to be $300.0 million. Hollys share of this
cost is $225.0 million. On July 17, 2008, Holly announced the purchase of Musket
Corporations Cedar City, Utah terminal and rail facilities that will serve as part of the UNEV
Pipelines Cedar City Terminal. Hollys UNEV project is in the final stage of the Bureau of Land Management permit process. Since it is
anticipated that the permit to proceed will now be received during the second quarter of 2009, Holly is currently evaluating
whether to maintain the current completion schedule for UNEV of early 2010 or whether from a commercial perspective, it
would be better to delay completion until the fall of 2010.
Holly is currently working on a project to deliver additional crude oils to its Navajo Refinery,
including a 70-mile pipeline from Centurion Pipeline L.P.s Slaughter Station in west Texas to
Lovington, New Mexico, and a 65-mile pipeline from Lovington to Artesia, New Mexico. Under
provisions of the Omnibus Agreement with Holly we will have an option to
purchase Hollys investment in the project at a purchase price to be negotiated with Holly. The
projects will increase the pipeline capacity between Lovington and Artesia by 40,000 bpd. The cost
of the projects is expected to be $90.0 million and construction is currently expected to be
completed and the projects to become fully operational in the fourth quarter of 2009.
We are currently working on a capital improvement project that will provide increased flexibility
and capacity to our Intermediate Pipelines enabling us to accommodate increased volumes following
Hollys Navajo Refinery capacity expansion. This project is expected to be completed in mid 2009
at an estimated cost of $5.1 million.
Also, we are currently converting an existing 12-mile crude oil pipeline to a natural gas pipeline
at an estimated cost of $1.9 million scheduled for completion in early 2009.
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We expect that our currently planned expenditures for maintenance capital as well as expenditures
for acquisitions and capital development projects such as the UNEV Pipeline, SLC Pipeline, South
System expansion and Holly crude oil projects described above will be funded with existing cash
balances, cash generated by operations, the sale of additional limited partner units, the issuance
of debt securities or advances under our $300.0 million senior secured revolving credit agreement
maturing August 2011 (the Credit Agreement), or a combination thereof. With the current
conditions in the credit and equity markets there may be limits on our ability to issue new debt or
equity securities. Additionally, due to pricing in the current 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 and Hollys crude oil project. We are not
obligated to purchase these assets nor are we subject to any fees or penalties if HEPs board of
directors decide not to proceed with either of these opportunities.
SAFETY AND MAINTENANCE
We perform preventive and normal maintenance on all of our pipeline systems and make repairs and
replacements when necessary or appropriate. We also conduct routine and required inspections of
our pipelines and other assets as required by code or regulation. We inject corrosion inhibitors
into our mainlines to help control internal corrosion. External coatings and impressed current
cathodic protection systems are used to protect against external corrosion. We conduct all
cathodic protection work in accordance with National Association of Corrosion Engineers standards.
We regularly monitor, test and record the effectiveness of these corrosion-inhibiting systems.
We monitor the structural integrity of selected segments of our pipeline systems through a program
of periodic internal inspections using both dent pigs and electronic smart pigs, as well as
hydrostatic testing that conforms to federal standards. We follow these inspections with a review
of the data and we make repairs as necessary to ensure the integrity of the pipeline. We have
initiated a risk-based approach to prioritizing the pipeline segments for future smart pig runs or
other approved integrity testing methods. We believe this approach will ensure that the pipelines
that have the greatest risk potential receive the highest priority in being scheduled for
inspections or pressure tests for integrity. Our inspection process complies with all Department
of Transportation (DOT) and Code of Federal Regulations 49 CFR Part 195 requirements.
Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response
personnel are located along the pipelines. Employees participate in simulated spill deployment
exercises on a
regular basis. They also participate in actual spill response boom deployment exercises in planned
spill scenarios in accordance with Oil Pollution Act of 1990 requirements. We believe that all of
our pipelines have been constructed and are maintained in all material respects in accordance with
applicable federal, state, and local laws and the regulations and standards prescribed by the
American Petroleum Institute, the DOT, and accepted industry practice.
At our terminals, tanks designed for gasoline storage are equipped with internal or external
floating roofs that minimize emissions and prevent potentially flammable vapor accumulation between
fluid levels and the roof of the tank. Our terminal facilities have facility response plans, spill
prevention and control plans, and other plans and programs to respond to emergencies.
Many of our terminal loading racks are protected with water deluge systems activated by either heat
sensors or an emergency switch. Several of our terminals are also protected by foam systems that
are activated in case of fire. All of our terminals are subject to participation in a
comprehensive environmental management program to assure compliance with applicable air, solid
waste, and wastewater regulations.
COMPETITION
As a result of our physical integration with Hollys Navajo and Woods Cross Refineries, our
contractual relationship with Holly under the Omnibus Agreement and the three Holly pipelines and
terminals
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agreements, we believe that we will not face significant competition for barrels of
refined products transported from Hollys Refineries, particularly during the term of the Holly
PTA, Holly IPA and Holly CPTA expiring in 2019, 2020 and 2023, respectively. Additionally, with
our contractual relationship with Alon under the Alon PTA, we believe that we will not face
significant competition for those barrels of refined products we transport from Alons Big Spring
Refinery, particularly during the term of our Alon PTA expiring in 2020.
However, we do face competition from other pipelines that may be able to supply the end-user
markets of Holly or Alon with refined products on a more competitive basis. Additionally, If
Hollys wholesale customers reduced their purchases of refined products due to the increased
availability of cheaper product from other suppliers or for other reasons, the volumes transported
through our pipelines could be reduced, which, subject to the minimum revenue commitments, could
cause a decrease in cash and revenues generated from our operations.
The petroleum refining business is highly competitive. Among Hollys competitors are some of the
worlds largest integrated petroleum companies, which have their own crude oil supplies and
distribution and marketing systems. Holly competes with independent refiners as well. Competition
in particular geographic areas is affected primarily by the amounts of refined products produced by
refineries located in such areas and by the availability of refined products and the cost of
transportation to such areas from refineries located outside those areas.
In addition, we face competition from trucks that deliver product in a number of areas we serve.
Although their costs may not be competitive for longer hauls or large volume shipments, trucks
compete effectively for incremental and marginal volumes in many areas we serve. The availability
of truck transportation places some competitive constraints on us.
Historically, the significant majority of the throughput at our terminal facilities has come from
Holly, with the exception of third-party receipts at the Spokane terminal, Alon volumes at El Paso,
and the Abilene and Wichita Falls terminals that serve Alons Big Springs Refinery. Under the
terms of the Holly PTA and the Holly CPTA, we continue to receive a significant portion of the
throughput at our terminal facilities from Holly.
Our ten refined product terminals compete with other independent terminal operators as well as
integrated oil companies on the basis of terminal location, price, versatility and services
provided. Our competition primarily comes from integrated petroleum companies, refining and
marketing companies, independent terminal companies and distribution companies with marketing and
trading arms.
RATE REGULATION
Some of our existing pipelines are subject to rate regulation by the FERC under the Interstate
Commerce Act. The Interstate Commerce Act requires that tariff rates for oil pipelines, a category
that includes crude oil and petroleum product pipelines, be just and reasonable and
non-discriminatory. The Interstate Commerce Act permits challenges to rates that are already on
file and in effect by complaint. A successful challenge under a complaint may result in the
complainant obtaining damages or reparations for up to two years prior to the date the complaint
was filed. The Interstate Commerce Act also permits challenges to a proposed new or changed rate
by a protest. A successful challenge under a protest may result in the protestant obtaining
refunds or reparations from the date the proposed new or changed rate was filed. In either
challenge process, the third party must be able to show it has a substantial economic interest in
those rates to proceed. The FERC generally has not investigated interstate rates on its own
initiative but will likely become a party to any proceedings when the rates receive either a
complaint or a protest. However, the FERC is not prohibited from bringing an interstate rate under
investigation without a third party intervention.
While the FERC regulates the rates for interstate shipments on our refined product pipelines, the
New Mexico Public Regulation Commission regulates the rates for intrastate shipments in New Mexico,
the Texas Railroad Commission regulates the rates for intrastate shipments in Texas, and the Idaho
Public Utilities Commission regulates the rates for intrastate shipments in Idaho. State
commissions have
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generally not been aggressive in regulating common carrier pipelines and have
generally not investigated the rates or practices of petroleum pipelines in the absence of shipper
complaints, and we do not believe the intrastate tariffs now in effect are likely to be challenged.
However, a state regulatory commission could investigate our rates if such a challenge were filed.
ENVIRONMENTAL REGULATION AND REMEDIATION
Our operation of pipelines, terminals, and associated facilities in connection with the storage and
transportation of refined products 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. Although 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.
We inspect our pipelines regularly using equipment rented from third-party suppliers. Third
parties also assist us in interpreting the results of the inspections.
Under the Omnibus Agreement, Holly has also 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 Omnibus Agreement
provides environmental indemnification of up to $15.0 million through 2014 for the assets
transferred to us at the time of our initial public offering in 2004 and up to $2.5 million through
2015 for the Intermediate Pipelines acquired in July 2005. In February 2008, Holly amended the
Omnibus Agreement to provide an additional $7.5 million of indemnification through 2023 for
environmental noncompliance and remediation liabilities specific to the Crude Pipelines and Tankage
Assets.
Additionally, 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, for a ten year term expiring in 2015, will indemnify us subject to a
$100,000 deductible and a $20.0 million maximum liability cap.
Contamination resulting from spills of refined products and crude oil is not unusual within the
petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a
result of past operations have resulted in contamination of the environment, including soils and
groundwater. Site conditions, including soils and groundwater, are being evaluated at a few of our
properties where operations may have resulted in releases of hydrocarbons and other wastes, none of
which we believe will have a significant effect on our operations since the remediation of such
releases would be covered under environmental indemnification agreements.
In the third quarter of 2008, we discovered a crude oil leak on a section of pipeline recently
acquired from Holly. We have initiated clean-up activities and have accrued $0.2 million for
estimated future remediation costs.
There are additional environmental remediation projects that are currently in progress that relate
to certain assets acquired from Holly. Certain of these projects were underway prior to our
purchase and
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represent liabilities of Holly Corporation as the obligation for future remediation activities was
retained by Holly. The remaining projects, including assessment and monitoring activities, are
covered under the Holly environmental indemnification discussed above and also represent
liabilities of Holly Corporation.
We may experience future releases into the environment from our pipelines and terminals or discover
historical releases that were previously unidentified or not assessed. Although we maintain an
extensive inspection and audit program designed, as applicable, to prevent, detect and address
these releases promptly, damages and liabilities incurred due to any future environmental releases
from our assets, nevertheless, have the potential to substantially affect our business.
EMPLOYEES
To carry out our operations, HLS employs 121 people who provide direct support to our operations.
Holly Logistic Services, L.L.C. considers its employee relations to be good. Neither we nor our
general partner have employees. We reimburse Holly for direct expenses that Holly or its
affiliates incurs on our behalf for the employees of HLS.
Item 1A. Risk Factors
Investing in us involves a degree of risk, including the risks described below. You should
carefully consider the following risk factors together with all of the other information included
in this Annual Report on Form 10-K, including the financial statements and related notes, when
deciding to invest in us. Additional risks and uncertainties not currently known to us or that we
currently deem to be immaterial may also materially and adversely affect our business operations.
If any of the following risks were to actually occur, our business, financial condition, results of
operations or treatment of unitholders could be materially and adversely affected.
RISKS RELATED TO OUR BUSINESS
We depend upon Holly and particularly its Navajo Refinery for a majority of our revenues; if those
revenues were significantly reduced or if Hollys financial condition materially deteriorated,
there would be a material adverse effect on our results of operations.
For the year ended December 31, 2008, Holly accounted for 72% of the revenues of our petroleum
product and crude pipelines and 70% of the revenues of our terminals and truck loading racks. We
expect to continue to derive a majority of our revenues from Holly for the foreseeable future. If
Holly satisfies only its minimum obligations under the Holly PTA, Holly IPA and Holly CPTA or is
unable to meet its minimum annual payment commitment for any reason, including due to prolonged
downtime or a shutdown at the Navajo Refinery or the Woods Cross Refinery, our revenues and cash
flow would decline.
Any significant curtailing of production at the Navajo Refinery could, by reducing throughput in
our pipelines and terminals, result in our realizing materially lower levels of revenues and cash
flow for the duration of the shutdown. For the year ended December 31, 2008, production from the
Navajo Refinery accounted for 67% of the throughput volumes transported by our refined product and
crude pipelines. The Navajo Refinery also received 100% of the petroleum products shipped on our
Intermediate Pipelines. Operations at the Navajo Refinery could be partially or completely shut
down, temporarily or permanently, as the result of:
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competition from other refineries and pipelines that may be able to supply the
refinerys end-user markets on a more cost-effective basis; |
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operational problems such as catastrophic events at the refinery, labor difficulties or
environmental proceedings or other litigation that compel the cessation of all or a portion
of the operations at the refinery; |
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planned maintenance or capital projects; |
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increasingly stringent environmental laws and regulations, such as the Environmental
Protection Agencys gasoline and diesel sulfur control requirements that limit the
concentration of sulfur in motor gasoline and diesel fuel for both on-road and non-road
usage as well as various state and federal emission requirements that may affect the
refinery itself; |
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an inability to obtain crude oil for the refinery at competitive prices; or |
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a general reduction in demand for refined products in the area due to: |
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a local or national recession or other adverse economic condition that results
in lower spending by businesses and consumers on gasoline and diesel fuel; |
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higher gasoline prices due to higher crude oil prices, higher taxes or stricter
environmental laws or regulations; or |
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a shift by consumers to more fuel-efficient or alternative fuel vehicles or an
increase in fuel economy, whether as a result of technological advances by
manufacturers, legislation either mandating or encouraging higher fuel economy or the
use of alternative fuel or otherwise. |
The magnitude of the effect on us of any shutdown would depend on the length of the shutdown and
the extent of the refinery operations affected by the shutdown. We have no control over the factors
that may lead to a shutdown or the measures Holly may take in response to a shutdown. Holly makes
all decisions at the Navajo Refinery concerning levels of production, regulatory compliance,
refinery turnarounds (planned shutdowns of individual process units within the refinery to perform
major maintenance activities), labor relations, environmental remediation and capital expenditures;
is responsible for all related costs; and is under no contractual obligation to us to maintain
operations at the Navajo Refinery.
Furthermore, Hollys obligations under the Holly PTA and Holly IPA would be temporarily suspended
during the occurrence of a force majeure that renders performance impossible with respect to an
asset for at least 30 days. If such an event were to continue for a year, we or Holly could
terminate the agreements. The occurrence of any of these events could reduce our revenues and cash
flows.
We depend on Alon and particularly its Big Spring Refinery for a substantial portion of our
revenues; if those revenues were significantly reduced, there would be a material adverse effect on
our results of operations.
For the year ended December 31, 2008, Alon accounted for 16% of the combined revenues of our
petroleum product and crude pipelines and of our terminals and truck loading racks, including
revenues we received from Alon under a capacity lease agreement.
On February 18, 2008, Alon experienced an explosion and fire at its Big Spring refinery that
resulted in the shutdown of production. In early April, Alon reopened its Big Spring refinery and
resumed production at one-half of refinery capacity until late September when production was
restored to full capacity. Lost production and reduced operations attributable to this incident
resulted in a significant decrease in third party shipments and related revenues on our refined
product pipelines during the first nine months of 2008. As a result of related contractual minimum
commitments and resulting shortfall billings, the incidents did not materially affect our
distributable cash flow.
Another decline in production at Alons Big Spring Refinery would materially reduce the volume of
refined products we transport and terminal for Alon. As a result, our revenues would be materially
adversely affected. The Big Spring Refinery could partially or completely shut down its operations,
temporarily or permanently, due to factors affecting its ability to produce refined products or for
planned maintenance or capital projects. Such factors would include the factors discussed above
under the discussion of risk factors for the Navajo Refinery.
The magnitude of the effect on us of any shutdown depends on the length of the shutdown and the
extent of the refinery operations affected. We have no control over the factors that may lead to a
shutdown or
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the measures Alon may take in response to a shutdown. Alon makes all decisions and is responsible
for all costs at the Big Spring Refinery concerning levels of production, regulatory compliance,
refinery turnarounds, labor relations, environmental remediation and capital expenditures.
In addition, under the Alon PTA, if we are unable to transport or terminal refined products that
Alon is prepared to ship, then Alon has the right to reduce its minimum volume commitment to us
during the period of interruption. If a force majeure event occurs beyond the control of either of
us, we or Alon could terminate the Alon pipelines and terminals agreement after the expiration of
certain time periods. The occurrence of any of these events could reduce our revenues and cash
flows.
We are exposed to the credit risks of our key customers.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. As
stated above, we receive substantial revenues from both Holly and Alon under their respective
pipelines and terminals agreements. In addition, a subsidiary of BP Plc (BP) is our largest
shipper on the Rio Grande Pipeline, a joint venture in which we own a 70% interest and from which
we derived 8% of our revenues for the year ended December 31, 2008.
If any of our key customers default on their obligations to us, our financial results could be
adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their
own operating and regulatory risks.
Competition from other pipelines that may be able to supply our shippers customers with refined
products at a lower price could cause us to reduce our rates or could reduce our revenues.
We and our shippers could face increased competition if other pipelines are able to competitively
supply our shippers end-user markets with refined products. The Longhorn Pipeline is a 72,000 bpd
common carrier pipeline that delivers refined products utilizing a direct route from the Texas Gulf
Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the
Arizona market. Longhorn Partners Pipeline, L.P., owner of the Longhorn Pipeline, has put the
pipeline up-for-sale. Although, Longhorn Partners Pipeline, L.P. did not complete a previously
planned 72,000 bpd to 125,000 bpd capacity expansion project, a subsequent owner could resume and
ultimately complete this planned expansion project under its own initiative. Increased supplies of
refined product delivered by the Longhorn Pipeline and Kinder Morgans El Paso to Phoenix pipeline
could result in additional downward pressure on wholesale refined product prices and refined
product margins in El Paso and related markets. Additionally, further increases in products from
Gulf Coast refiners entering the El Paso and Arizona markets on this pipeline and a resulting
increase in the demand for shipping product on the interconnecting common carrier pipelines could
cause a decline in the demand for refined product from Holly and/or Alon. This could reduce our
opportunity to earn revenues from Holly and Alon in excess of their minimum volume commitment
obligations.
An additional factor that could affect some of Hollys and Alons markets is excess pipeline
capacity from the West Coast into our shippers Arizona markets on the pipeline from the West Coast
to Phoenix. Additional increases in shipments of refined products from the West Coast into our
shippers Arizona markets could result in additional downward pressure on refined product prices
that, if sustained over the long term, could influence product shipments by Holly and Alon to these
markets.
A material decrease in the supply, or a material increase in the price, of crude oil available to
Hollys and Alons refineries and a corresponding decrease in demand for refined products in the
markets served by our pipelines and terminals, could materially reduce our revenues.
The volume of refined products we transport in our refined products pipelines depends on the level
of production of refined products from Hollys and Alons refineries, which, in turn, depends on
the availability of attractively-priced crude oil produced in the areas accessible to those
refineries. In order to maintain or increase production levels at their refineries, our shippers
must continually contract for new crude oil supplies. A material decrease in crude oil production
from the fields that supply their refineries, as a result of depressed commodity prices, decreased
demand, lack of drilling activity, natural production
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declines or otherwise, could result in a decline in the volume of crude oil our shippers refine,
absent the availability of transported crude oil to offset such declines. Such an event would
result in an overall decline in volumes of refined products transported through our pipelines and
therefore a corresponding reduction in our cash flow. In addition, the future growth of our
shippers operations will depend in part upon whether our shippers can contract for additional
supplies of crude oil at a greater rate than the rate of natural decline in their currently
connected supplies.
Fluctuations in crude oil prices can greatly affect production rates and investments by third
parties in the development of new oil reserves. Drilling activity generally decreases as crude oil
prices decrease. We and our shippers have no control over the level of drilling activity in the
areas of operations, the amount of reserves underlying the wells and the rate at which production
from a well will decline, or producers or their production decisions, which are affected by, among
other things, prevailing and projected energy prices, demand for hydrocarbons, geological
considerations, governmental regulation and the availability and cost of capital. Similarly, a
material increase in the price of crude oil supplied to our shippers refineries without an
increase in the market value of the products produced by the refineries, either temporary or
permanent, which caused a reduction in the production of refined products at the refineries, would
cause a reduction in the volumes of refined products we transport, and our cash flow could be
adversely affected.
Finally, our business depends in large part on the demand for the various petroleum products we
gather, transport and store in the markets we serve. Reductions in that demand adversely affect our
business. Market demand varies based upon the different end uses of the petroleum products we
gather, transport and store. We cannot predict the impact of future fuel conservation measures,
alternate fuel requirements, government regulation, technological advances in fuel economy and
energy-generation devices, exploration and production activities, and actions by foreign nations,
any of which could reduce the demand for the petroleum products in the areas we serve.
We may not be able to retain existing customers or acquire new customers.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain
current revenues and cash flows depends on a number of factors outside our control, including
competition from other pipelines and the demand for refined products in the markets that we serve.
Alons obligations to lease capacity on the Artesia-Orla-El Paso pipeline have remaining terms that
expire beginning in 2012 through 2018. Our pipelines and terminals agreements with Holly and Alon
expire beginning in 2019 through 2023. Additionally, Rio Grande executed a 5-year throughput
agreement with PMI Trading Ltd. in January 2009 that expires 2014. This contract can be cancelled
by either party following 180 days notice after June 30, 2011.
Our operations are subject to federal, state, and local laws and regulations relating to product
quality specifications, environmental protection and operational safety that could require us to
make substantial expenditures.
Our pipelines and terminal operations are subject to increasingly strict environmental and safety
laws and regulations. Also, the transportation and storage of refined products produces a risk that
refined products and other hydrocarbons may be suddenly or gradually released into the environment,
potentially causing substantial expenditures for a response action, significant government
penalties, liability to government agencies for natural resources damages, personal injury or
property damages to private parties and significant business interruption. We own or lease a number
of properties that have been used to store or distribute refined products for many years. Many of
these properties have also been operated by third parties whose handling, disposal, or release of
hydrocarbons and other wastes were not under our control. If we were to incur a significant
liability pursuant to environmental laws or regulations, it could have a material adverse effect on
us. We are also subject to the requirements of OSHA, and comparable state statutes. Any violation
of OSHA could impose substantial costs on us.
New environmental laws and regulations, including new regulations relating to alternative energy
sources and the risk of global climate change, new interpretations of existing laws and
regulations, increased governmental enforcement or other developments could require us to make
additional unforeseen
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expenditures. There is growing consensus that some form of regulation will be forthcoming at the
federal level in the United States with respect to greenhouse gas emissions (including carbon
dioxide, methane and nitrous oxides). Also, as a result of the U.S. Supreme Courts decision in
April 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas
emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new
legislation specifically addressing emissions of greenhouse gases. New legislation or regulatory
programs that restrict emissions of greenhouse gases in areas where we conduct business could
adversely affect our operations and demand for our services. Furthermore, the costs of
environmental and safety regulations are already significant and additional or more stringent
regulation could increase these costs or could otherwise adversely affect our business.
Petroleum products that we store and transport are sold by our customers for consumption into the
public market. Various federal, state and local agencies have the authority to prescribe specific
product quality specifications of refined products. Changes in product quality specifications or
blending requirements could reduce our throughput volume, require us to incur additional handling
costs or require capital expenditures. For example, different product specifications for different
markets impact the fungibility of the products in our system and could require the construction of
additional storage. If we are unable to recover these costs through increased revenues, our cash
flows and ability to pay cash distributions could be adversely affected. In addition, changes in
the product quality of the products we receive on our petroleum products pipeline system could
reduce or eliminate our ability to blend products.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not
be adequately insured.
Our operations are subject to operational hazards and unforeseen interruptions such as natural
disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical
failures and other events beyond our control. These events might result in a loss of equipment or
life, injury, or extensive property damage, as well as an interruption in our operations. We may
not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates
and exclusions from coverage may limit our ability to recover the amount of the full loss in all
situations. As a result of market conditions, premiums and deductibles for certain of our insurance
policies could increase. In some instances, certain insurance could become unavailable or available
only for reduced amounts of coverage. If we were to incur a significant liability for which we were
not fully insured, it could have a material adverse effect on our financial position.
Any reduction in the capacity of, or the allocations to, our shippers on interconnecting,
third-party pipelines could cause a reduction of volumes transported in our pipelines and through
our terminals.
Holly, Alon and the other users of our pipelines and terminals are dependent upon connections to
third-party pipelines to receive and deliver crude oil and refined products. Any reduction of
capacities of these interconnecting pipelines due to testing, line repair, reduced operating
pressures, or other causes could result in reduced volumes transported in our pipelines or through
our terminals. Similarly, if additional shippers begin transporting volumes of refined products
over interconnecting pipelines, the allocations to existing shippers in these pipelines would be
reduced, which could also reduce volumes transported in our pipelines or through our terminals. For
example, the common carrier pipelines used by Holly to serve the Arizona and Albuquerque markets
are currently operated at or near capacity and are subject to proration. As a result, the volumes
of refined product that Holly and other shippers have been able to deliver to these markets have
been limited. The flow of additional products into El Paso for shipment to Arizona could further
exacerbate such constraints on deliveries to Arizona. Any reduction in volumes transported in our
pipelines or through our terminals could adversely affect our revenues and cash flows.
If our assumptions concerning population growth are inaccurate or if Hollys growth strategy is not
successful, our ability to grow may be adversely affected.
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Our growth strategy is dependent upon:
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the accuracy of our assumption that many of the markets that we currently serve or have
plans to serve in the Southwestern and Rocky Mountain regions of the United States will
experience population growth that is higher than the national average; and |
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the willingness and ability of Holly to capture a share of this additional demand in its
existing markets and to identify and penetrate new markets in the Southwestern and Rocky
Mountain regions of the United States. |
If our assumptions about growth in market demand prove incorrect, Holly may not have any incentive
to increase refinery capacity and production or shift additional throughput to our pipelines, which
would adversely affect our growth strategy. Furthermore, Holly is under no obligation to pursue a
growth strategy. If Holly chooses not to gain, or is unable to gain additional customers in new or
existing markets in the Southwestern and Rocky Mountain regions of the United States, our growth
strategy would be adversely affected. Moreover, Holly may not make acquisitions that would provide
acquisition opportunities to us; or, if those opportunities arise, they may not be financed by us
or on terms attractive to us. Finally, Holly also will be subject to integration risks with respect
to any new acquisitions it chooses to make.
Growing our business by constructing new pipelines and terminals, or expanding existing ones,
subjects us to construction risks.
One of the ways we may grow our business is through the construction of new pipelines and terminals
or the expansion of existing ones. The construction of a new pipeline or the expansion of an
existing pipeline, by adding horsepower or pump stations or by adding a second pipeline along an
existing pipeline, involves numerous regulatory, environmental, political, and legal uncertainties,
most of which are beyond our control. These projects may not be completed on schedule or at all or
at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure
of funds on a particular project. For instance, if we build a new pipeline, the construction will
occur over an extended period of time and we will not receive any material increases in revenues
until after completion of the project. Moreover, we may construct facilities to capture anticipated
future growth in demand for refined products in a region in which such growth does not materialize.
As a result, new facilities may not be able to attract enough throughput to achieve our expected
investment return, which could adversely affect our results of operations and financial condition.
Rate regulation may not allow us to recover the full amount of increases in our costs.
The FERC regulates the tariff rates for interstate movements on our pipeline systems. The primary
rate-making methodology of the FERC is price indexing. We use this methodology in all of our
interstate markets. The indexing method allows a pipeline to increase its rates based on a
percentage change in the producer price index for finished goods. If the index falls, we will be
required to reduce our rates that are based on the FERCs price indexing methodology if they exceed
the new maximum allowable rate. In addition, changes in the index might not be large enough to
fully reflect actual increases in our costs. The FERCs rate-making methodologies may limit our
ability to set rates based on our true costs or may delay the use of rates that reflect increased
costs. Any of the foregoing would adversely affect our revenues and cash flow.
If our interstate or intrastate tariff rates are successfully challenged, we could be required to
reduce our tariff rates, which would reduce our revenues.
Under the FERC indexing methodology contained in the Code of Federal Regulations at 18 CFR 342-3,
our interstate pipeline tariff rates are deemed just and reasonable. If a party with an economic
interest were to file either a protest or a complaint against our tariff rates, or the FERC were to
initiate an investigation of our rates, then our existing rates could be subject to detailed
review. If our rates were found to be in excess of levels justified by our cost of service, the
FERC could order us to reduce our rates, and to refund the amount by which the rates were
determined to be excessive, plus interest. In
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addition, a state commission could also investigate our intrastate rates or our terms and
conditions of service on its own initiative or at the urging of a shipper or other interested
party. If a state commission found that our rates exceeded levels justified by our cost of service,
the state commission could order us to reduce our rates. Any such reductions may result in lower
revenues and cash flows if additional volumes and / or capacity are unavailable to offset such rate
reductions.
Holly and Alon have agreed not to challenge, or to cause others to challenge or assist others in
challenging, our tariff rates in effect during the terms of their respective pipelines and
terminals agreements. These agreements do not prevent other current or future shippers from
challenging our tariff rates.
Potential changes to current petroleum pipeline rate-making methods and procedures may impact the
federal and state regulations under which we will operate in the future.
The regulatory agencies that regulate our systems periodically implement new rules, regulations and
terms and conditions of services subject to their jurisdiction. New initiatives or orders may
adversely affect the rates charged for our services. If the FERCs petroleum pipeline rate-making
methodology changes, the new methodology could result in tariffs that generate lower revenues and
cash flow. Furthermore, competition from other pipeline systems may prevent us from raising our
tariff rates even if regulatory agencies permit us to do so.
The fees we charge to third parties under transportation and storage agreements may not escalate
sufficiently to cover increases in our costs, and the agreements may not be renewed or may be
suspended in some circumstances.
Our costs may increase at a rate greater than the rate that the fees we charge to third parties
increase pursuant to our contracts with them. Furthermore, third parties may not renew their
contracts with us. Additionally, some third parties obligations under their agreements with us may
be permanently or temporarily reduced upon the occurrence of certain events, some of which are
beyond our control, including force majeure events wherein the supply of crude oil or refined
products is curtailed or cut off. Force majeure events include (but are not limited to)
revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts,
fires, storms, floods, acts of God, explosions and mechanical or physical failures of our equipment or
facilities or those of third parties. If the escalation of fees is insufficient to cover increased
costs, if third parties do not renew or extend their contracts with us or if any third party
suspends or terminates its contracts with us, our financial results would be negatively impacted.
Terrorist attacks, and the threat of terrorist attacks or domestic vandalism, have resulted in
increased costs to our business. Continued hostilities in the Middle East or other sustained
military campaigns may adversely impact our results of operations.
The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001,
and the threat of future terrorist attacks, on the energy transportation industry in general, and
on us in particular, is not known at this time. Increased security measures taken by us as a
precaution against possible terrorist attacks or vandalism have resulted in increased costs to our
business. Uncertainty surrounding continued hostilities in the Middle East or other sustained
military campaigns may affect our operations in unpredictable ways, including disruptions of crude
oil supplies and markets for refined products, and the possibility that infrastructure facilities
could be direct targets of, or indirect casualties of, an act of terror.
Changes in the insurance markets attributable to terrorist attacks could make certain types of
insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may
be significantly more expensive than our existing insurance coverage. Instability in the financial
markets as a result of terrorism or war could also affect our ability to raise capital including
our ability to repay or refinance debt.
Our leverage may limit our ability to borrow additional funds, comply with the terms of our
indebtedness or capitalize on business opportunities.
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As of December 31, 2008, the principal amount of our total outstanding debt was $385.0 million. Our
results of operations, cash flows and financial position could be adversely affected by significant
increases in interest rates above current levels. Various limitations in our Credit Agreement and
the indenture for our Senior Notes may reduce our ability to incur additional debt, to engage in
some transactions and to capitalize on business opportunities. Any subsequent refinancing of our
current indebtedness or any new indebtedness could have similar or greater restrictions.
Our leverage could have important consequences. We will require substantial cash flow to meet our
payment obligations with respect to our indebtedness. Our ability to make scheduled payments, to
refinance our obligations with respect to our indebtedness or our ability to obtain additional
financing in the future will depend on our financial and operating performance, which, in turn, is
subject to prevailing economic conditions and to financial, business and other factors. We believe
that we will have sufficient cash flow from operations and available borrowings under our Credit
Agreement to service our indebtedness. However, a significant downturn in our business or other
development adversely affecting our cash flow could materially impair our ability to service our
indebtedness. If our cash flow and capital resources are insufficient to fund our debt service
obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot
assure you that we would be able to refinance our existing indebtedness at maturity or otherwise or
sell assets on terms that are commercially reasonable.
The instruments governing our debt contain restrictive covenants that may prevent us from engaging
in certain beneficial transactions. The agreements governing our debt generally require us to
comply with various affirmative and negative covenants including the maintenance of certain
financial ratios and restrictions on incurring additional debt, entering into mergers,
consolidations and sales of assets, making investments and granting liens. Additionally, our
contribution agreements with Alon, and our purchase and contribution agreements with Holly with
respect to the Intermediate Pipelines and the Crude Pipelines and Tankage Assets restrict us from
selling the pipelines and terminals acquired from Alon or Holly, as applicable, and from prepaying
more than $30.0 million of the Senior Notes until 2015 and any of the $171.0 million borrowed under
the Credit Agreement for the purchase of the Crude Pipelines and Tankage assets until 2018, subject
to certain limited exceptions. Our leverage may adversely affect our ability to fund future working
capital, capital expenditures and other general partnership requirements, future acquisitions,
construction or development activities, or to otherwise fully realize the value of our assets and
opportunities because of the need to dedicate a substantial portion of our cash flow from
operations to payments on our indebtedness or to comply with any restrictive terms of our
indebtedness. Our leverage may also make our results of operations more susceptible to adverse
economic and industry conditions by limiting our flexibility in planning for, or reacting to,
changes in our business and the industry in which we operate and may place us at a competitive
disadvantage as compared to our competitors that have less debt.
We may not be able to obtain funding on acceptable terms or at all because of the deterioration of the credit and capital markets. This may hinder or
prevent us from meeting our future capital needs.
Global financial markets and economic conditions have been, and continue to be, disrupted and
volatile due to a variety of factors, including significant write-offs in the financial services
sector and the current weak economic conditions. As a result, the cost of raising money in the debt
and equity capital markets has increased substantially while the availability of funds from those
markets has diminished significantly. In particular, as a result of concerns about the stability of
financial markets generally and the solvency of lending counterparties specifically, the cost of
obtaining money from the credit markets generally has increased as many lenders and institutional
investors have increased interest rates, enacted tighter lending standards, refused to refinance
existing debt on similar terms or at all and reduced, or in some cases ceased, to provide funding
to borrowers. In addition, lending counterparties under existing revolving credit facilities and
other debt instruments may be unwilling or unable to meet their funding obligations. Due to these
factors, we cannot be certain that new debt or equity financing will be available on acceptable
terms. If funding is not available when needed, or is available only on unfavorable terms, we may
be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth
strategy, complete future
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acquisitions or announced and future pipeline construction projects, take advantage of other
business opportunities or respond to competitive pressures, any of which could have a material
adverse effect on our revenues and results of operations.
We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or
increased competition for investment opportunities.
Our strategy contemplates growth through the development and acquisition of crude, intermediate and
refined products transportation and storage assets while maintaining a strong balance sheet. This
strategy includes constructing and acquiring additional assets and businesses to enhance our
ability to compete effectively and diversifying our asset portfolio, thereby providing more stable
cash flow. We regularly consider and enter into discussions regarding, and are currently
contemplating and/or pursuing, potential joint ventures, stand alone projects or other transactions
that we believe will present opportunities to realize synergies, expand our role in our chosen
businesses and increase our market position.
We will require substantial new capital to finance the future development and acquisition of assets
and businesses. Any limitations on our access to capital will impair our ability to execute this
strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire
accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory
terms, if at all. The primary factors that influence our cost of equity include market
conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for
legal and accounting services. The primary factors influencing our cost of borrowing include
interest rates, credit spreads, covenants, underwriting or loan origination fees and similar
charges we pay to lenders.
In addition, we are experiencing increased competition for the types of assets and businesses we
have historically purchased or acquired. Increased competition for a limited pool of assets could
result in our losing to other bidders more often or acquiring assets at less attractive prices.
Either occurrence would limit our ability to fully execute our growth strategy. Our inability to
execute our growth strategy may materially adversely affect our ability to maintain or pay higher
distributions in the future.
Ongoing maintenance of effective internal controls in accordance with Section 404 of the
Sarbanes-Oxley Act could cause us to incur additional expenditures of time and financial resources.
We regularly document and test our internal control procedures in order to satisfy the requirements
of Section 404 of the Sarbanes-Oxley Act, which requires annual management assessments of the
effectiveness of our internal controls over financial reporting and a report by our independent
registered public accounting firm on our controls over financial reporting. If, in the future, we
fail to maintain the adequacy of our internal controls, as such standards are modified,
supplemented or amended from time to time; we may not be able to ensure that we can conclude on an
ongoing basis that we have effective internal controls over financial reporting in accordance with
Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal
control environment could cause us to incur substantial expenditures of management time and
financial resources to identify and correct any such failure.
We may be unsuccessful in integrating the operations of any future acquisitions with our
operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.
From time to time, we evaluate and acquire assets and businesses that we believe complement our
existing assets and businesses. Acquisitions may require substantial capital or the incurrence of
substantial indebtedness. If we consummate any future acquisitions, our capitalization and results
of operations may change significantly. Acquisitions and business expansions involve numerous
risks, including difficulties in the assimilation of the assets and operations of the acquired
businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and
the businesses associated with them and new geographic areas and the diversion of managements
attention from other business concerns. Further, unexpected costs and challenges may arise whenever
businesses with
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different operations or management are combined, and we may experience unanticipated delays in
realizing the benefits of an acquisition. Also, following an acquisition, we may discover
previously unknown liabilities associated with the acquired business for which we have no recourse
under applicable indemnification provisions.
Due to our lack of asset diversification, adverse developments in our businesses could materially
and adversely affect our financial condition, results of operations, or cash flows.
We rely exclusively on the revenues generated from our business. Due to our lack of asset
diversification, an adverse development in our business could have a significantly greater impact
on our financial condition and results of operations than if we maintained more diverse assets.
We do not own all of the land on which our pipeline systems and facilities are located, which could
disrupt our operations.
We do not own all of the land on which our pipeline systems and facilities are located, and we are,
therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the
right to construct and operate pipelines on land owned by third parties and government agencies for
specified periods of time. If we were to lose these rights through an inability to renew
right-of-way contracts or otherwise, we may be required to relocate our pipelines and our business
could be adversely affected. Additionally, it may become more expensive for us to obtain new
rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or
renewing existing rights-of-way increases, it may adversely affect our operations and cash flows
available for distribution to unitholders.
Our business may suffer if any of our key senior executives or other key employees discontinues
employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may
make it difficult for us to maintain labor productivity.
Our future success depends to a large extent on the services of our key senior executives and key
senior employees. Our business depends on our continuing ability to recruit, train and retain
highly qualified employees in all areas of our operations, including accounting, business
operations, finance and other key back-office and mid-office personnel. The competition for these
employees is intense, and the loss of these executives or employees could harm our business. If
any of these executives or other key personnel resign or become unable to continue in their present
roles and are not adequately replaced, our business operations could be materially adversely
affected. We do not maintain any key man life insurance for any executives. Furthermore, our
operations require skilled and experienced laborers with proficiency in multiple tasks.
In certain cases we have the right to be indemnified by third parties for environmental
liabilities, and our results of operation and our ability to make distributions to our unitholders
could be adversely affected if a third party fails to satisfy an indemnification obligation owed to
us.
In connection with our past acquisitions of pipelines, tankage, terminals and related assets from
Holly and Alon, we have entered into environmental agreements with them pursuant to which they have
agreed to indemnify us for certain pre-closing environmental liabilities discovered within
specified time periods after the date of the applicable acquisition. These indemnities continue
through 2014 for the assets contributed to us by Holly at our initial public offering, through 2015
for the Intermediate Pipelines acquired from Holly and the refined products pipelines, tankage and
terminals acquired from Alon, and through 2023 for the Crude Pipelines and Tankage Assets acquired
from Holly. Other third parties are also obligated to indemnify us for ongoing remediation pursuant
to separate indemnification obligations. Our results of operation and our ability to make cash
distributions to our unitholders could be adversely affected in the future if Holly, Alon, or other
third parties fail to satisfy an indemnification obligation owed to us.
RISKS TO COMMON UNITHOLDERS
Holly and its affiliates have conflicts of interest and limited fiduciary duties, which may permit
them to favor their own interests.
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Currently, Holly indirectly owns the 2% general partner interest and a 44% limited partner interest
in us and owns and controls our general partner, HEP Logistics Holdings, L.P. Conflicts of interest
may arise between Holly and its affiliates, including our general partner, on the one hand, and us,
on the other hand. As a result of these conflicts, the general partner may favor its own interests
and the interests of its affiliates over our interests. These conflicts include, among others, the
following situations:
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Holly, as a shipper on our pipelines, has an economic incentive not to cause us to seek
higher tariff rates or terminalling fees, even if such higher rates or terminalling fees
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neither our partnership agreement nor any other agreement requires Holly to pursue a
business strategy that favors us or utilizes our assets, including whether to increase or
decrease refinery production, whether to shut down or reconfigure a refinery, or what
markets to pursue or grow. Hollys directors and officers have a fiduciary duty to make
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our general partner is allowed to take into account the interests of parties other than
us, such as Holly, in resolving conflicts of interest; |
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our general partner determines which costs incurred by Holly and its affiliates are
reimbursable by us; |
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our partnership agreement does not restrict our general partner from causing us to pay
it or its affiliates for any services rendered to us or entering into additional
contractual arrangements with any of these entities on our behalf; |
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our general partner determines the amount and timing of our asset purchases and sales,
capital expenditures and borrowings, each of which can affect the amount of cash available
to us; and |
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our general partner controls the enforcement of obligations owed to us by our general
partner and its affiliates, including the pipelines and terminals agreement with Holly. |
Cost reimbursements, which will be determined by our general partner, and fees due our general
partner and its affiliates for services provided, are substantial.
Under our Omnibus Agreement, we are currently obligated to pay Holly an administrative fee of $2.3
million per year for the provision by Holly or its affiliates of various general and administrative
services for our benefit. The administrative fee may increase if we make an acquisition that
requires an increase in the level of general and administrative services that we receive from Holly
or its affiliates. Our general partner will determine the amount of general and administrative
expenses that will be properly allocated to us in accordance with the terms of our partnership
agreement. In addition, our general partner and its affiliates are entitled to reimbursement for
all other expenses they incur on our behalf, including the salaries of and the cost of employee
benefits for employees of Holly Logistic Services, L.L.C. who provide services to us. Prior to
making any distribution on the common units, we will reimburse our general partner and its
affiliates, including officers and directors of the general partner, for all expenses incurred on
our behalf, plus the administrative fee. The reimbursement of expenses and the payment of fees
could adversely affect our ability to make distributions. The general partner has sole discretion
to determine the amount of these expenses. Our general partner and its affiliates also may provide
us other services for which we are charged fees as determined by our general partner.
Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on
matters affecting our business and, therefore, limited ability to influence managements decisions
regarding our business. Unitholders did not elect our general partner or the board of directors of
our
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general partners general partner and have no right to elect our general partner or the board of
directors of our general partners general partner on an annual or other continuing basis. The
board of directors of our general partners general partner is chosen by the members of our general
partners general partner. Furthermore, if unitholders are dissatisfied with the performance of our
general partner, they will have little ability to remove our general partner. As a result of these
limitations, the price at which the common units trade could be diminished because of the absence
or reduction of a takeover premium in the trading price.
The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single
class is required to remove the general partner. Unitholders will be unable to remove the general
partner without its consent because the general partner and its affiliates own sufficient units to
prevent its removal. Also, if the general partner is removed without cause during the subordination
period and units held by the general partner and its affiliates are not voted in favor of that
removal, all remaining subordinated units will automatically convert into common units and any
existing arrearages on the common units will be extinguished. A removal of the general partner
under these circumstances would adversely affect the common units by prematurely eliminating their
distribution and liquidation preference over the subordinated units, which would otherwise have
continued until we had met certain distribution and performance tests. Cause is narrowly defined to
mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding
the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in
its capacity as our general partner. Cause does not include most cases of charges of poor
management of the business, so the removal of the general partner because of the unitholders
dissatisfaction with the general partners performance in managing our partnership will most likely
result in the termination of the subordination period.
Furthermore, unitholders voting rights are further restricted by the partnership agreement
provision providing that any units held by a person that owns 20% or more of any class of units
then outstanding, other than the general partner, its affiliates, their transferees, and persons
who acquired such units with the prior approval of the board of directors of the general partners
general partner, cannot vote on any matter. Our partnership agreement also contains provisions
limiting the ability of unitholders to call meetings or to acquire information about our
operations, as well as other provisions limiting the unitholders ability to influence the manner
or direction of management.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a
sale of all or substantially all of its assets without the consent of the unitholders. Furthermore,
our partnership agreement does not restrict the ability of the partners of our general partner from
transferring their respective partnership interests in our general partner to a third party. The
new partners of our general partner would then be in a position to replace the board of directors
and officers of the general partner of our general partner with their own choices and to control
the decisions taken by the board of directors and officers.
We may issue additional common units without unitholder approval, which would dilute an existing
unitholders ownership interests.
During the subordination period, our general partner, without the approval of our unitholders, may
cause us to issue up to 3,500,000 additional common units. Our general partner may also cause us to
issue an unlimited number of additional common units or other equity securities of equal rank with
the common units, without unitholder approval, in a number of circumstances such as:
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the issuance of common units in connection with acquisitions or capital improvements
that increase cash flow from operations per unit on an estimated pro forma basis; |
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issuances of common units to repay indebtedness, the cost of which to service is greater
than the distribution obligations associated with the units issued in connection with the
repayment of the indebtedness; |
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the conversion of subordinated units into common units; |
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the conversion of units of equal rank with the common units into common units under some
circumstances; |
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in the event of a combination or subdivision of common units; |
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issuances of common units under our employee benefit plans; or |
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the conversion of the general partner interest and the incentive distribution rights
into common units as a result of the withdrawal or removal of our general partner. |
The issuance by us of additional common units or other equity securities of equal or senior rank
will have the following effects:
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our unitholders proportionate ownership interest in us will decrease; |
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the amount of cash available for distribution on each unit may decrease; |
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because a lower percentage of total outstanding units will be subordinated units, the
risk that a shortfall in the payment of the minimum quarterly distribution will be borne by
our common unitholders will increase; |
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the relative voting strength of each previously outstanding unit may be diminished; and |
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the market price of the common units may decline, |
After the end of the subordination period that is currently expected to end as of July 1, 2009,
provided there is no significant decrease in our operating performance, we may issue an unlimited
number of limited partner interests of any type without the approval of our unitholders. Our
partnership agreement does not give our unitholders the right to approve our` issuance of equity
securities ranking junior to the common units at any time.
In establishing cash reserves, our general partner may reduce the amount of cash available for
distribution to unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash
reserves that it establishes are necessary to fund our future operating expenditures. In addition,
our partnership agreement permits our general partner to reduce available cash by establishing cash
reserves for the proper conduct of our business, to comply with applicable law or agreements to
which we are a party, or to provide funds for future distributions to partners. These cash reserves
will affect the amount of cash available to make the required payments to our debt holders or to
pay the minimum quarterly distribution on our common units every quarter.
Holly and its affiliates may engage in limited competition with us.
Holly and its affiliates may engage in limited competition with us. Pursuant to the Omnibus
Agreement among us, Holly and our general partner, Holly and its affiliates agreed not to engage in
the business of operating intermediate or refined product pipelines or terminals, crude oil
pipelines or terminals, truck racks or crude oil gathering systems in the continental United
States. The Omnibus Agreement, however, does not apply to:
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any business operated by Holly or any of its subsidiaries at the closing of our initial
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any business or asset that Holly or any of it subsidiaries acquires or constructs that
has a fair market value or construction cost of less than $5.0 million; and |
any business or asset that Holly or any of its subsidiaries acquires or constructs that has a fair
market value or construction cost of $5.0 million or more if we have been offered the opportunity
to purchase the business or asset at fair market value, and we decline to do so with the
concurrence of our conflicts committee.
In the event that Holly or its affiliates no longer control our partnership or there is a change of
control of Holly, the non-competition provisions of the omnibus agreement will terminate.
Our general partner may cause us to borrow funds in order to make cash distributions, even where
the purpose or effect of the borrowing benefits our general partner or its affiliates.
In some instances, our general partner may cause us to borrow funds from affiliates of Holly or
from third parties in order to permit the payment of cash distributions.
These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to
make a distribution on the subordinated units, to make incentive distributions, or to hasten the
expiration of the subordination period.
Our general partner has a limited call right that may require a holder of units to sell its common
units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our
general partner will have the right, but not the obligation, which it may assign to any of its
affiliates or to us, to acquire all, but not less than all, of the common units held by
unaffiliated persons at a price not less than their then-current market price. As a result, a
holder of common units may be required to sell its units at an undesirable time or price and may
not receive any return on its investment. A common unitholder may also incur a tax liability upon a
sale of its units.
A unitholder may not have limited liability if a court finds that unitholder actions constitute
control of our business.
Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a
general partner if a court determined that the right of unitholders to remove our general partner
or to take other action under our partnership agreement constituted participation in the control
of our business. Our general partner generally has unlimited liability for our obligations, such as
our debts and environmental liabilities, except for those contractual obligations that are
expressly made without recourse to our general partner.
In addition, Section 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act
provides that under some circumstances, a unitholder may be liable to us for the amount of a
distribution for a period of three years from the date of the distribution.
TAX RISKS TO COMMON UNITHOLDERS
Our tax treatment depends on our status as a partnership for federal income tax purposes as well as
our not being subject to a material amount of entity-level taxation by individual states. If the
IRS were to treat us as a corporation for federal income tax purposes or we were to become subject
to additional amounts of entity-level taxation for state tax purposes, then our cash available for
distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on
our being treated as a partnership for federal income tax purposes. We have not requested, and do
not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
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Despite the fact that we are a limited partnership under Delaware law, it is possible in certain
circumstances for a partnership such as ours to be treated as a corporation for federal income tax
purposes. A change in our business (or a change in current law) could cause us to be treated as a
corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income
tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%.
Distributions to unitholders would generally be taxed again as corporate distributions, and no
income, gains, losses or deductions would flow through to unitholders. Because a tax would be
imposed upon us as a corporation, our cash available for distribution to unitholders would be
substantially reduced. Therefore, treatment of us as a corporation would result in a material
reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a
substantial reduction in the value of our common units.
Current law may change so as to cause us to be treated as a corporation for federal income tax
purposes or otherwise subject us to entity-level taxation, possibly on a retroactive basis. At the
federal level, legislation has been proposed that would eliminate partnership tax treatment for
certain publicly traded partnerships. It could be amended prior to enactment in a manner that does
apply to us. We are unable to predict whether any of these changes, or other proposals, will
ultimately be enacted. Any such changes could negatively impact the value of an investment in our
common units. At the state level, because of widespread state budget deficits and other reasons,
several states are evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise and other forms of taxation. Imposition of such a tax on us
by Texas and, if applicable, by any other state will reduce the cash available for distribution to
unitholders.
Our partnership agreement provides that if a law is enacted or existing law is modified or
interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to
entity-level taxation for federal, state or local income tax purposes, the minimum quarterly
distribution amount and the target distribution amounts may be adjusted to reflect the impact of
that law on us.
If the IRS contests the federal income tax positions we take, the market for our common units may
be adversely impacted and the cost of any IRS contest will reduce our cash available for
distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for
federal income tax purposes or any other matter affecting us. The IRS may adopt positions that
differ from the positions we have taken or may take on tax matters. It may be necessary to resort
to administrative or court proceedings to sustain some or all of the positions we take. A court
may not agree with some or all of the positions we take. Any contest with the IRS may materially
and adversely impact the market for our common units and the price at which they trade. In
addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our
general partner because the costs will reduce our cash available for distribution.
Unitholders will be required to pay taxes on their share of our income even if they do not receive
any cash distributions from us.
Because our unitholders are treated as partners to whom we allocate taxable income, which could be
different in amount than the cash we distribute, they are required to pay any federal income taxes
and, in some cases, state and local income taxes on their share of our taxable income even if they
receive no cash distributions from us. Unitholders may not receive cash distributions from us
equal to their share of our taxable income or even equal to the actual tax liability resulting from
that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a unitholder sells its common units, it will recognize gain or loss equal to the difference
between the amount realized and its tax basis in those common units. A unitholders amount
realized will be measured by the sum of the cash and the fair market value of other property, if
any, received by the unitholder, plus its share of our nonrecourse liabilities. Because the amount
realized will include the unitholders share of our
-27-
nonrecourse liabilities, the gain recognized by the unitholder on the sale of its units could
result in a tax liability in excess of any cash it receives from the sale. Distributions in excess
of a unitholders allocable share of our net taxable income (excess distributions) decrease the
unitholders tax basis in its common units, which includes its share of nonrecourse liabilities.
Such excess distributions with respect to the units sold become taxable income to the unitholder if
it sells such units at a price greater than its tax basis in those units, even if the price the
unitholder receives is less than its original cost. Moreover, a substantial portion of the amount
realized, whether or not representing gain, may be taxed as ordinary income due to potential
recapture items, including depreciation recapture.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that
may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual
retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For
example, virtually all of our income allocated to organizations that are exempt from federal income
tax, including IRAs and other retirement plans, will be unrelated business taxable income and will
be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the
highest applicable effective tax rate, and non-U.S. persons will be required to file United States
federal tax returns and pay tax on their share of our taxable income.
We treat each purchaser of common units as having the same tax benefits without regard to the
actual common units purchased. The IRS may challenge this treatment, which could adversely affect
the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons,
we have adopted depreciation and amortization positions that may not conform to all aspects of
existing Treasury Regulations. A successful IRS challenge to those positions could adversely
affect the amount of tax benefits available to a unitholder. It also could affect the timing of
these tax benefits or the amount of gain from the sale of common units and could have a negative
impact on the value of our common units or result in audit adjustments to a unitholders tax
returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our
units each month based upon the ownership of our units on the first day of each month, instead of
on the basis of the date a particular unit is transferred. The IRS may challenge this treatment,
which could change the allocation of items of income, gain, loss and deduction among our
unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our
units each month based upon the ownership of our units on the first day of each month, instead of
on the basis of the date a particular unit is transferred. The use of this proration method may not
be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new
Treasury Regulations were issued, we may be required to change the allocation of items of income,
gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a short seller to cover a short sale of units may be
considered as having disposed of those units. If so, it would no longer be treated for tax purposes
as a partner with respect to those units during the period of the loan and may recognize gain or
loss from the disposition.
Because a unitholder whose units are loaned to a short seller to cover a short sale of units may
be considered as having disposed of the loaned units, it may no longer be treated for tax purposes
as a partner with respect to those units during the period of the loan to the short seller and the
unitholder may recognize gain or loss from such disposition. Moreover, during the period of the
loan to the short seller, any of our income, gain, loss or deduction with respect to those units
may not be reportable by the unitholder and any cash distributions received by the unitholder as to
those units could be fully taxable as ordinary income. Unitholders desiring to assure their status
as partners and avoid the risk of gain recognition from a loan to a
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short seller are urged to modify any applicable brokerage account agreements to prohibit their
brokers from borrowing their units.
We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and
deduction between the general partner and the unitholders. The IRS may challenge this treatment,
which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we determine the fair
market value of our assets and allocate any unrealized gain or loss attributable to our assets to
the capital accounts of our unitholders and our general partner. Our methodology may be viewed as
understating the value of our assets. In that case, there may be a shift of income, gain, loss and
deduction between certain unitholders and the general partner, which may be unfavorable to such
unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have
a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our
tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our
valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible
and intangible assets, and allocations of income, gain, loss and deduction between the general
partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of
taxable income or loss being allocated to our unitholders. It also could affect the amount of gain
from our unitholders sale of common units and could have a negative impact on the value of the
common units or result in audit adjustments to our unitholders tax returns without the benefit of
additional deductions.
The reporting of partnership tax information is complicated and subject to audits.
We furnish each unitholder with a Schedule K-1 that sets forth the unitholders share of our
income, gains, losses and deductions. We cannot guarantee that these schedules will be prepared in
a manner that conforms in all respects to statutory or regulatory requirements or to administrative
pronouncements of the IRS. Further, our tax return may be audited, which could result in an audit
of a unitholders individual tax return and increased liabilities for taxes because of adjustments
resulting from the audit.
There are limits on the deductibility of our losses that may adversely affect our unitholders.
There are a number of limitations that may prevent unitholders from using their allocable share of
our losses as a deduction against unrelated income. In the case of taxpayers subject to the passive
loss rules (generally, individuals and closely-held corporations), any losses generated by us will
only be available to offset our future income and cannot be used to offset income from other
activities, including other passive activities or investments. Unused losses may be deducted when
the unitholder disposes of its entire investment in us in a fully taxable transaction with an
unrelated party. A unitholders share of our net passive income may be offset by unused losses from
us carried over from prior years, but not by losses from other passive activities, including losses
from other publicly traded partnerships. Other limitations that may further restrict the
deductibility of our losses by a unitholder include the at-risk rules and the prohibition against
loss allocations in excess of the unitholders tax basis in its units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month
period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if there
is a sale or exchange of 50% or more of the total interests in our capital and profits within a
twelve-month period. Our termination would, among other things, result in the closing of our
taxable year for all unitholders, which would result in us filing two tax returns (and our
unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant
deferral of depreciation deductions allowable in computing our taxable income. In the case of a
unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of
our taxable year may also result in more than twelve months of our taxable income or loss being
includable in its taxable income for the year of termination. Our termination currently would not
affect our classification as a partnership for federal income tax purposes, but instead, we would
be treated as a
-29-
new partnership for tax purposes. If treated as a new partnership, we must make new tax elections
and could be subject to penalties if we are unable to determine that a termination occurred.
Unitholders will likely be subject to state and local taxes and return filing requirements as a
result of investing in our common units.
In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, such
as state and local income taxes, unincorporated business taxes and estate, inheritance, or
intangible taxes that are imposed by the various jurisdictions in which we do business or own
property. Unitholders likely will be required to file state and local income tax returns and pay
state and local income taxes in some or all of these various jurisdictions. Further, unitholders
may be subject to penalties for failure to comply with those requirements. We currently own
property and conduct business in Texas, New Mexico, Arizona, Colorado, Utah, Idaho, Oklahoma and
Washington. We may own property or conduct business in other states or foreign countries in the
future. It is the unitholders responsibility to file all federal, state, local, and foreign tax
returns.
Item 1B. Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
Item 2. Properties
PIPELINES
Our refined product pipelines transport light refined products from Hollys Navajo Refinery in New
Mexico and Alons Big Spring Refinery in Texas to their customers in the metropolitan and rural
areas of Texas, New Mexico, Arizona, Colorado, Utah, Oklahoma and northern Mexico. The refined
products transported in these pipelines include conventional gasolines, federal, state and local
specification reformulated gasoline, low-octane gasoline for oxygenate blending, distillates that
include high- and low-sulfur diesel and jet fuel and LPGs (such as propane, butane and isobutane).
Our intermediate product pipelines consist of two parallel pipelines that originate at Hollys
Lovington, New Mexico refining facilities and terminate at Hollys Artesia, New Mexico refining
facilities. These pipelines transport intermediate feedstocks and crude oil for Hollys refining
operations in New Mexico.
Our crude pipelines consist of crude oil trunk, gathering and connection pipelines located in west
Texas and New Mexico that deliver crude oil to Hollys Navajo Refinery and crude oil and refined
product pipelines that support Hollys Woods Cross Refinery.
Our pipelines are regularly inspected, are well maintained and we believe, are in good repair.
Generally, other than as provided in the pipelines and terminal agreements with Holly and Alon,
substantially all of our pipelines are unrestricted as to the direction in which product flows and
the types of refined products that we can transport on them. The FERC regulates the transportation
tariffs for interstate shipments on our refined product pipelines and state regulatory agencies
regulate the transportation tariffs for intrastate shipments on our pipelines.
The following table details the average aggregate daily number of barrels of petroleum products
transported on our pipelines in each of the periods set forth below for Holly and for third
parties.
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Years Ended December 31, |
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2008(2) |
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2007 |
|
2006 |
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2005(1) |
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2004 |
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Volumes transported for (bpd): |
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Holly |
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253,484 |
|
|
|
142,447 |
|
|
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126,929 |
|
|
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94,473 |
|
|
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65,525 |
|
Third parties (3) |
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38,330 |
|
|
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62,720 |
|
|
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62,655 |
|
|
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65,053 |
|
|
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29,967 |
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|
|
|
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|
|
|
|
|
|
|
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|
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|
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Total |
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291,814 |
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205,167 |
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189,584 |
|
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159,526 |
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95,492 |
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Total barrels in thousands (mbbls) |
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106,804 |
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74,886 |
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69,198 |
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58,227 |
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34,950 |
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(1) |
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Includes volumes transported on the pipelines acquired from Alon on February 28, 2005, and
volumes transported on the Intermediate Pipelines acquired on July 8, 2005. |
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(2) |
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Includes volumes transported on the Crude Pipelines acquired February 29, 2008. |
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(3) |
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Includes Rio Grande Pipeline volumes. |
The following table sets forth certain operating data for each of our crude oil and petroleum
product pipelines. Except as shown below, we own 100% of our pipelines. Throughput is the total
average number of barrels per day transported on a pipeline, but does not aggregate barrels moved
between different points on the same pipeline. Revenues reflect tariff revenues generated by
barrels shipped from an origin to a delivery point on a pipeline. Revenues also include payments
made by Alon under capacity lease arrangements on our Orla to El Paso pipeline. Under these
arrangements, we provide space on our pipeline for the shipment of up to 17,500 barrels of refined
product per day. Alon pays us whether or not it actually ships the full volumes of refined
products it is entitled to ship. To the extent Alon does not use its capacity, we are entitled to
use it. We calculate the capacity of our pipelines based on the throughput capacity for barrels of
gasoline equivalent that may be transported in the existing configuration; in some cases, this
includes the use of drag reducing agents.
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Approximate |
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Length |
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Origin and Destination |
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Diameter (inches) |
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(miles) |
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Capacity (bpd) |
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Refined Product Pipelines: |
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Artesia, NM to El Paso, TX |
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6 |
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156 |
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24,000 |
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Artesia, NM to Orla, TX to El Paso, TX |
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8/12/8 |
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215 |
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70,000 |
(1) |
Artesia, NM to Moriarty, NM(2) |
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12/8 |
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215 |
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45,000 |
(3) |
Moriarty, NM to Bloomfield, NM(2) |
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8 |
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191 |
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(3) |
Big Spring, TX to Abilene, TX |
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6/8 |
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105 |
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20,000 |
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Big Spring, TX to Wichita Falls, TX |
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6/8 |
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227 |
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23,000 |
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Wichita Falls, TX to Duncan, OK |
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6 |
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47 |
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21,000 |
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Midland, TX to Orla, TX |
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8/10 |
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135 |
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25,000 |
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Artesia, NM to Roswell, NM |
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4 |
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36 |
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5,300 |
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Woods Cross, UT |
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10/8 |
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6 |
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70,000 |
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Intermediate Product Pipelines: |
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Lovington, NM to Artesia, NM |
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8 |
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65 |
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48,000 |
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Lovington, NM to Artesia, NM |
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10 |
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65 |
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72,000 |
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Crude Pipelines: |
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Delivers to Hollys Navajo Refinery |
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Various |
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861 |
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Woods Cross, Utah |
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12 |
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4 |
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40,000 |
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Rio Grande Pipeline Company: |
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Rio Grande Pipeline(4) |
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8 |
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249 |
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27,000 |
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(1) |
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Includes 17,500 bpd of capacity on the Orla to El Paso segment of this pipeline that is
leased to Alon under capacity lease agreements. |
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(2) |
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The White Lakes Junction to Moriarty segment of our Artesia to Moriarty pipeline and the
Moriarty to Bloomfield pipeline is leased from Mid-America Pipeline Company, LLC
(Mid-America) under a long-term lease agreement. |
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(3) |
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Capacity for this pipeline is reflected in the information for the Artesia to Moriarty
pipeline. |
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(4) |
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We have a 70% joint venture interest in the entity that owns this pipeline that runs from
West TX to El Paso, TX. Capacity reflects a 100% interest. |
Holly shipped an aggregate of 68% of the petroleum products transported on our refined product
pipelines and 100% of the petroleum products transported on our Intermediate Pipelines and Crude
Oil pipelines in 2008. These pipelines transported approximately 95% of the light refined products
produced by Hollys Navajo Refinery in 2008.
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Artesia, New Mexico to El Paso, Texas
The Artesia to El Paso refined product pipeline is regulated by the FERC. It was constructed in
1959 and consists of 156 miles of 6-inch pipeline. This pipeline is used for the shipment of
refined products produced at Hollys Navajo Refinery to our El Paso terminal, where we deliver to
common carrier pipelines for transportation to Arizona, northern New Mexico and northern Mexico and
to the terminals tank farm for truck rack loading for local delivery by tanker truck. The refined
products shipped on this pipeline represented 14% of the total light refined products produced at
Hollys Navajo Refinery during 2008. Refined products produced at Hollys Navajo Refinery destined
for El Paso are transported on either this pipeline or our Artesia to Orla to El Paso pipeline.
Artesia, New Mexico to Orla, Texas to El Paso, Texas
The Artesia to Orla to El Paso refined product pipeline is a common-carrier pipeline regulated by
the FERC and consists of three segments:
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an 8-inch, 9-mile and a 12-inch, 72-mile segment from Hollys Navajo Refinery to Orla,
Texas; |
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a 12-inch, 126-mile segment from Orla to outside El Paso, Texas; and |
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an 8-inch, 8-mile segment from outside El Paso to our El Paso terminal |
There are two shippers on this pipeline, Holly and Alon. In 2008, this pipeline transported to our
El Paso terminal 61% of the light refined products produced at Hollys Navajo Refinery. As
mentioned above, refined products destined to the El Paso terminal are delivered to common carrier
pipelines for transportation to Arizona, northern New Mexico and northern Mexico and to the
terminals truck rack for local delivery by tanker truck.
At Orla, product is received into our tankage from Alons Big Spring Refinery via our FinTex
Pipeline. These volumes are then sent from Orla to El Paso, either directly from the Artesia to
Orla segment or from tankage in Orla.
Artesia, New Mexico to Moriarty, New Mexico
The Artesia to Moriarty refined product pipeline consists of a 60-mile, 12-inch pipeline from
Hollys Artesia facility to White Lakes Junction, New Mexico that was constructed in 1999, and
approximately 155 miles of 8-inch pipeline that was constructed in 1973 and extends from White
Lakes Junction to our Moriarty terminal, where it also connects to our Moriarty to Bloomfield
pipeline. We own the 12-inch pipeline from Artesia to White Lakes Junction. We lease the White
Lakes Junction to Moriarty segment of this pipeline and the Moriarty to Bloomfield pipeline
described below, from Mid-America Pipeline Company, LLC under a long-term lease agreement entered
into in 1996, which expires in 2017 and has two ten-year extensions at our option. At our Moriarty
terminal, volumes shipped on this pipeline can be transported to other markets in the area,
including Albuquerque, Santa Fe and west Texas, via tanker truck. The 155-mile White Lakes
Junction to Moriarty segment of this pipeline is operated by Mid-America (or its designee). Holly
is the only shipper on this pipeline. We currently pay a monthly fee (which is subject to
adjustments based on changes in the PPI) of $513,000 to Mid-America to lease the White Lakes
Junction to Moriarty and Moriarty to Bloomfield pipelines.
Moriarty, New Mexico to Bloomfield, New Mexico
The Moriarty to Bloomfield refined product pipeline was constructed in 1973 and consists of 191
miles of 8-inch pipeline leased from Mid-America. This pipeline serves our terminal in Bloomfield.
At our Bloomfield terminal, volumes shipped on this pipeline are transported to other markets in
the Four Corners area via tanker truck. This pipeline is operated by Mid-America (or its
designee). Holly is the only shipper on this pipeline.
Big Spring, Texas to Abilene, Texas
The Big Spring to Abilene refined product pipeline was constructed in 1957 and consists of 100
miles of 6-inch pipeline and 5 miles of 8-inch pipeline. This pipeline is used for the shipment of
refined products produced at Alons Big Spring Refinery to the Abilene terminal. Alon is the only
shipper on this pipeline.
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Big Spring, Texas to Wichita Falls, Texas
Segments of the Big Spring to Wichita Falls refined product pipeline were constructed in 1969 and
1989, and consist of 95 miles of 6-inch pipeline and 132 miles of 8-inch pipeline. This pipeline
is used for the shipment of refined products produced at Alons Big Spring Refinery to the Wichita
Falls terminal. Alon is the only shipper on this pipeline.
Wichita Falls, Texas to Duncan, Oklahoma
The Wichita Falls to Duncan refined product pipeline is a common carrier and is regulated by the
FERC. It was constructed in 1958 and consists of 47 miles of 6-inch pipeline. This pipeline is
used for the shipment of refined products from the Wichita Falls terminal to Alons Duncan
terminal, which we do not own. Alon is the only shipper on this pipeline.
Midland, Texas to Orla, Texas
Segments of the Midland to Orla refined product pipeline were constructed in 1928 and 1998, and
consist of 50 miles of 10-inch pipeline and 85 miles of 8-inch pipeline. This pipeline is used for
the shipment of refined products produced at Alons Big Spring Refinery from Midland to our tank
farm at Orla. Alon is the only shipper on this pipeline.
Artesia, New Mexico to Roswell, New Mexico
The 36-mile 4-inch diameter Artesia to Roswell refined product pipeline delivers jet fuel only to
tanks located at our jet fuel terminal in Roswell. Holly is the only shipper on this pipeline.
Woods Cross, Utah refined product pipelines
The Woods Cross refined products pipelines consist of three pipeline segments. The Woods Cross to
Pioneer Terminal segment consists of 2 miles of 8-inch pipeline and is used for product shipments
to and through the Pioneer Terminal. The Woods Cross to Pioneer segment represents 2 miles of
10-inch pipeline that is also used for product shipments to and through the Pioneer Terminal. The
Woods Cross to Chevron Pipelines Salt Lake Products Pipeline segment consists of 4 miles of 8-inch
pipeline and is used for product shipments from the Woods Cross Refinery to Chevrons North Salt
Lake pumping station. Holly is the only shipper on these pipelines.
8 Pipeline from Lovington, New Mexico to Artesia, New Mexico
The 65-mile 8-inch diameter pipeline was constructed in 1981. This pipeline is used for the
shipment of intermediate feedstocks, crude oil and LPGs from Hollys Lovington facility to its
Artesia facility.
10 Pipeline from Lovington, New Mexico to Artesia, New Mexico
The 65-mile 10-inch diameter pipeline was constructed in 1999. This pipeline is used for the
shipment of intermediate feedstocks and crude oil from Hollys Lovington facility to its Artesia
facility. Holly is the only shipper on this pipeline.
Crude Oil Pipelines that deliver to Hollys Navajo Refinery
The crude oil mainline gathering and mainline pipelines deliver crude oil to Hollys Navajo
Refinery and consists of 850 miles of 4-inch and 6-inch diameter pipeline and 450,000 barrels of
crude oil tankage. The crude oil mainline pipelines consists of five pipeline segments that
deliver crude oil to the Navajo Lovington facility and eight pipeline segments that deliver crude
oil to the Navajo Artesia facility.
The Lovington system crude oil mainlines include five pipeline segments consisting of a 23-mile
12-inch pipeline from Russell to Lovington, a 20-mile 8-inch pipeline from Russell to Hobbs, an
11-mile 6-inch and 8-inch pipeline from Crouch to Lovington, a 20-mile 8-inch pipeline from Hobbs
to Lovington and a 6-mile 6-inch pipeline from Gaines to Jobs.
The Artesia system crude oil mainlines include eight pipeline segments consisting of an 11-mile
6-inch
pipeline from Beeson to North Artesia, a 7-mile 4-inch and 6-inch pipeline from Barnsdall to North
Artesia, a 2-mile 8-inch pipeline from the Barnsdall jumper line to Lovington, a 4-mile 4-inch
pipeline from the Artesia Station to North Artesia, a 6-mile 8-inch pipeline from North Artesia to
Evans Junction, a 1-mile 6-inch pipeline from Abo to Evans Junction and a 12-mile 8-inch pipeline
from Evans Junction to Artesia.
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Woods Cross, Utah crude oil pipeline
This 4-mile 12-inch pipeline is used for the shipment of crude oil from Chevron Pipe Lines North
Salt Lake City station to Hollys Woods Cross Refinery.
Rio Grande Pipeline
We own a 70% interest in Rio Grande, a joint venture that owns a 249-mile, 8-inch common carrier
LPG pipeline regulated by the FERC. The other owner of Rio Grande is a subsidiary of BP. The
pipeline originates from a connection with an Enterprise pipeline in west Texas at Lawson Junction,
which serves as its primary receipt point, although there is an additional receipt point near
Midland, Texas. The pipeline terminates at the Mexico border near San Elizario, Texas. The
pipeline transports LPGs for ultimate use by Petróleos Mexicanos (PEMEX, the government-owned
energy company of Mexico.) Rio Grande does not own any facilities or pipelines in Mexico. The
pipeline has a current capacity of approximately 27,000 bpd. This pipeline was originally
constructed in the mid 1950s, was first reconditioned in 1988, and subsequently reconditioned in
1996 and 2003. Approximately 75 miles of this pipeline has been replaced with new pipe, and an
additional 50 miles has been recoated.
Currently, only LPGs are transported on this pipeline. In January 2009, Rio Grande
executed a 5-year throughput agreement with PMI Trading Ltd. that provides for the shipment of a
minimum average of 16,000 bpd of LPGs during the term of the agreement. The tariff rates and
shipping regulations are regulated by the FERC. In January 2005, Rio Grande appointed us as
operator of the pipeline system effective April 1, 2005 through January 31, 2010. As operator, we
receive a management fee of $1.3 million per year, adjusted annually for any changes in the PPI.
An officer of HLS is one of the two members of Rio Grandes management committee.
REFINED PRODUCT TERMINALS, TRUCK RACKS AND REFINERY CRUDE OIL TANKAGE
Refined Product Terminals and Truck Racks
Our refined product terminals receive products from pipelines connected to Hollys Navajo and Woods
Cross Refineries and Alons Big Spring Refinery. We then distribute them to Holly and third
parties, who in turn deliver them to end-users and retail outlets. Our terminals are generally
complementary to our pipeline assets and serve Hollys and Alons marketing activities. Terminals
play a key role in moving product to the end-user market by providing the following services:
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distribution; |
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blending to achieve specified grades of gasoline; |
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other ancillary services that include the injection of additives and filtering of
jet fuel; and |
|
|
|
|
storage and inventory management. |
Typically, our refined product terminal facilities consist of multiple storage tanks and are
equipped with automated truck loading equipment that operates 24 hours a day. This automated
system provides for control of security, allocations, and credit and carrier certification by
remote input of data by our customers. In addition, nearly all of our terminals are equipped with
truck loading racks capable of providing automated blending to individual customer specifications.
Our refined product terminals derive most of their revenues from terminalling fees paid by
customers. We charge a fee for transferring refined products from the terminal to trucks or to
pipelines connected to the terminal. In addition to terminalling fees, we generate revenues by
charging our customers fees for blending, injecting additives, and filtering jet fuel. Holly
currently accounts for the substantial majority of our refined product terminal revenues.
-34-
The table below sets forth the total average throughput for our refined product terminals in each
of the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
2005(1) |
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refined products terminalled for (bpd): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Holly |
|
|
109,539 |
|
|
|
119,910 |
|
|
|
118,202 |
|
|
|
120,795 |
|
|
|
114,991 |
|
Third parties |
|
|
32,737 |
|
|
|
45,457 |
|
|
|
43,285 |
|
|
|
42,334 |
|
|
|
24,821 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
142,276 |
|
|
|
165,367 |
|
|
|
161,487 |
|
|
|
163,129 |
|
|
|
139,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (mbbls) |
|
|
52,073 |
|
|
|
60,359 |
|
|
|
58,943 |
|
|
|
59,542 |
|
|
|
51,171 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes volumes for the terminals and tank farm acquired from Alon February 28, 2005. |
The following table outlines the locations of our terminals and their storage capacities, number of
tanks, supply source, and mode of delivery:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number |
|
|
|
|
|
|
Storage Capacity |
|
of |
|
Supply |
|
|
Terminal Location |
|
(barrels) |
|
Tanks |
|
Source |
|
Mode of Delivery |
|
El Paso, TX
|
|
|
507,000 |
|
|
|
16 |
|
|
Pipeline/ rail
|
|
Truck/Pipeline |
Moriarty, NM
|
|
|
189,000 |
|
|
|
9 |
|
|
Pipeline
|
|
Truck |
Bloomfield, NM
|
|
|
193,000 |
|
|
|
7 |
|
|
Pipeline
|
|
Truck |
Tucson, AZ(1)
|
|
|
176,000 |
|
|
|
9 |
|
|
Pipeline
|
|
Truck |
Mountain Home, ID(2)
|
|
|
120,000 |
|
|
|
3 |
|
|
Pipeline
|
|
Pipeline |
Boise, ID(3)
|
|
|
111,000 |
|
|
|
9 |
|
|
Pipeline
|
|
Pipeline |
Burley, ID(3)
|
|
|
70,000 |
|
|
|
7 |
|
|
Pipeline
|
|
Truck |
Spokane, WA
|
|
|
333,000 |
|
|
|
32 |
|
|
Pipeline/Rail
|
|
Truck |
Abilene, TX
|
|
|
127,000 |
|
|
|
5 |
|
|
Pipeline
|
|
Truck/Pipeline |
Wichita Falls, TX
|
|
|
220,000 |
|
|
|
11 |
|
|
Pipeline
|
|
Truck/Pipeline |
Roswell, NM (2)
|
|
|
25,000 |
|
|
|
1 |
|
|
Pipeline
|
|
Truck |
Orla tank farm
|
|
|
135,000 |
|
|
|
5 |
|
|
Pipeline
|
|
Pipeline |
Artesia facility truck rack
|
|
|
N/A |
|
|
|
N/A |
|
|
Refinery
|
|
Truck |
Woods Cross facility
truck rack
|
|
|
N/A |
|
|
|
N/A |
|
|
Refinery
|
|
Truck/Pipeline |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,206,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The underlying ground at the Tucson terminal is leased. |
|
(2) |
|
Handles only jet fuel. |
|
(3) |
|
We have a 50% ownership interest in these terminals. The capacity and throughput information
represents the proportionate share of capacity and throughput attributable to our ownership
interest. |
El Paso Terminal
We receive light refined products at this terminal from Hollys Artesia facility through our
Artesia to El Paso and Artesia to Orla to El Paso pipelines and by rail that account for
approximately 97% of the volumes at this terminal. We also receive product from Alons Big Spring
Refinery that accounted for 3% of the volumes at this terminal in 2008. Refined products received
at this terminal are sold locally via the truck rack or transported to our Tucson terminal and
other terminals in Phoenix on Kinder Morgans East System pipeline. Competition in this market
includes a refinery and terminal owned by Western Refining, Inc., a joint venture pipeline and
terminal owned by ConocoPhillips and NuStar Energy, L.P. (NuStar) and a terminal connected to the
Longhorn Pipeline.
Moriarty Terminal
We receive light refined products at this terminal from Hollys Artesia facility through our
pipelines. Refined products received at this terminal are sold locally, via the truck rack; Holly
is our only customer at this terminal. There are no competing terminals in Moriarty.
Bloomfield Terminal
We receive light refined products at this terminal from Hollys Artesia facility through our
pipelines. Refined products received at this terminal are sold locally, via the truck rack; Holly
is our only customer at this terminal. Competition in this market includes a refinery and truck
loading rack owned by Western Refining, Inc.
-35-
Tucson Terminal
We own 100% of the improvements and lease underlying ground at this terminal. The Tucson terminal
receives light refined products from Kinder Morgans East System pipeline, which transports refined
products from Hollys Artesia facility that it receives at our El Paso terminal. Refined products
received at this terminal are sold locally, via the truck rack. Competition in this market
includes terminals owned by Kinder Morgan and CalJet.
Mountain Home Terminal
We receive jet fuel from third parties at this terminal that is transported on Chevrons Salt Lake
City to Boise, Idaho pipeline. We then transport the jet fuel from the Mountain Home terminal
through our 13-mile, 4-inch pipeline to the United States Air Force base outside of Mountain Home.
Our pipeline associated with this terminal is the only pipeline that supplies jet fuel to the air
base. We are paid a single fee, from the Defense Energy Support Center, for injecting, storing,
testing and transporting jet fuel at this terminal.
Boise Terminal
We and Sinclair Transportation Company (Sinclair) each own a 50% interest in the Boise terminal.
Sinclair is the operator of the terminal. The Boise terminal receives light refined products from
Holly and Sinclair shipped through Chevrons pipeline originating in Salt Lake City, Utah. The
Woods Cross Refinery, as well as other refineries in the Salt Lake City area, and Pioneer Pipeline
Co.s terminal in Salt Lake City are connected to the Chevron pipeline. All loading of products
out of the Boise terminal is conducted at Chevrons loading rack, which is connected to the Boise
terminal by pipeline. Holly and Sinclair are the only customers at this terminal.
Burley Terminal
We and Sinclair each own a 50% interest in the Burley terminal. Sinclair is the operator of the
terminal. The Burley terminal receives product from Holly and Sinclair shipped through Chevrons
pipeline originating in Salt Lake City, Utah. Refined products received at this terminal are sold
locally, via the truck rack. Holly and Sinclair are the only customers at this terminal.
Spokane Terminal
This terminal is connected to the Woods Cross Refinery via a Chevron common carrier pipeline. The
Spokane terminal also is supplied by Chevron and Yellowstone pipelines and by rail and truck.
Refined products received at this terminal are sold locally, via the truck rack. We have several
major customers at this terminal. Other terminals in the Spokane area include terminals owned by
ExxonMobil and ConocoPhillips.
Abilene Terminal
This terminal receives refined products from Alons Big Spring Refinery, which accounted for all of
its volumes in 2008. Refined products received at this terminal are sold locally via a truck rack
or pumped over a 2-mile pipeline to Dyess Air Force Base. Alon is the only customer at this
terminal.
Wichita Falls Terminal
This terminal receives refined products from Alons Big Spring Refinery, which accounted for all of
its volumes in 2008. Refined products received at this terminal are sold via a truck rack or
shipped via pipeline connections to Alons terminal in Duncan, Oklahoma and also to NuStars
Southlake Pipeline. Alon is the only customer at this terminal.
Roswell Terminal
This terminal receives jet fuel from Hollys Navajo Refinery, which accounted for all of its
volumes in 2008, for further transport to Cannon Air Force Base and to Albuquerque, New Mexico. We
lease this terminal under an agreement that expires in September 2011.
Orla Tank Farm
The Orla tank farm was constructed in 1998. It receives refined products from Alons Big Spring
Refinery that accounted for all of its volumes in 2008. Refined products received at the tank farm
are delivered into our Orla to El Paso pipeline. Alon is the only customer at this tank farm.
-36-
Artesia Facility Truck Rack
The truck rack at Hollys Artesia facility loads light refined products, produced at the facility,
onto tanker trucks for delivery to markets in the surrounding area. Holly is the only customer of
this truck rack.
Woods Cross Facility Truck Rack
The truck rack at Hollys Woods Cross facility loads light refined products produced at Hollys
Woods Cross Refinery onto tanker trucks for delivery to markets in the surrounding area. Holly is
the only customer of this truck rack. Holly also makes transfers to a common carrier pipeline at
this facility.
Refinery Crude Oil Tankage
Our refinery tankage consists of on-site crude oil tankage at Hollys Navajo and Woods Cross
Refineries. Our refinery tankage derives its revenues from fixed fees charged in providing the
Hollys refining facilities with approximately 600,000 barrels per month of crude storage.
The following table outlines the locations of our refinery crude oil tankage, storage capacity and
number of tanks:
|
|
|
|
|
|
|
|
|
|
|
Storage |
|
Number |
|
|
Capacity |
|
of |
Refinery Location |
|
(barrels) |
|
Tanks |
|
Artesia , NM |
|
|
166,000 |
|
|
|
2 |
|
Lovington, NM |
|
|
267,000 |
|
|
|
2 |
|
Woods Cross, UT |
|
|
180,000 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
613,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TRUCK FLEET
We have a truck fleet consisting of 7 trucks and 13 trailers that transport crude oil to Hollys
Wood Cross Refinery. Our trucking operations are conducted in Utah only and Holly is our only
customer.
PIPELINE AND TERMINAL CONTROL OPERATIONS
All of our pipelines are operated via geosynchronous satellite, microwave, radio and frame relay
communication systems from our central control room located in Artesia, New Mexico. We also
monitor activity at our terminals from this control room.
The control center operates with state-of-the-art System Control and Data Acquisition, or SCADA,
systems. Our control center is equipped with computer systems designed to continuously monitor
operational data, including refined product and crude oil throughput, flow rates, and pressures.
In addition, the control center monitors alarms and throughput balances. The control center
operates remote pumps, motors, engines, and valves associated with the delivery of refined products
and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound
automatic alarms if operational conditions outside of pre-established parameters occur, and provide
for remote-controlled shutdown of pump stations on the pipelines. Pump stations and
meter-measurement points on the pipelines are linked by satellite or telephone communication
systems for remote monitoring and control, which reduces our requirement for full-time on-site
personnel at most of these locations.
Item 3. Legal Proceedings
We are a party to various legal and regulatory proceedings, which we believe will not have a
material adverse impact on our financial condition, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth quarter of 2008.
-37-
PART II
|
|
|
Item 5. |
|
Market for the Registrants Common Units, Related Unitholder Matters and Issuer Purchases
of Common Units |
Our common limited partner units are traded on the New York Stock Exchange under the symbol HEP.
The following table sets forth the range of the daily high and low sales prices per common unit,
cash distributions to common unitholders and the trading volume of common units for the period
indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash |
|
Trading |
Years Ended December 31, |
|
High |
|
Low |
|
Distributions |
|
Volume |
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
33.46 |
|
|
$ |
14.93 |
|
|
$ |
0.755 |
|
|
|
3,901,900 |
|
Third Quarter |
|
$ |
39.16 |
|
|
$ |
26.01 |
|
|
$ |
0.745 |
|
|
|
2,537,800 |
|
Second Quarter |
|
$ |
47.03 |
|
|
$ |
37.33 |
|
|
$ |
0.735 |
|
|
|
1,914,000 |
|
First Quarter |
|
$ |
44.23 |
|
|
$ |
36.06 |
|
|
$ |
0.725 |
|
|
|
1,384,400 |
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
48.09 |
|
|
$ |
42.04 |
|
|
$ |
0.715 |
|
|
|
1,065,300 |
|
Third Quarter |
|
$ |
57.24 |
|
|
$ |
43.10 |
|
|
$ |
0.705 |
|
|
|
1,273,100 |
|
Second Quarter |
|
$ |
56.69 |
|
|
$ |
46.55 |
|
|
$ |
0.690 |
|
|
|
1,231,600 |
|
First Quarter |
|
$ |
49.97 |
|
|
$ |
39.50 |
|
|
$ |
0.675 |
|
|
|
948,900 |
|
A distribution for the quarter ended December 31, 2008 of $0.765 per unit is payable on February
13, 2009.
As of February 6, 2009, we had approximately 5,720 common unitholders, including beneficial owners of
common units held in street name.
We consider cash distributions to unitholders on a quarterly basis, although there is no assurance
as to the future cash distributions since they are dependent upon future earnings, cash flows,
capital requirements, financial condition and other factors. Our revolving credit facility
prohibits us from making cash distributions if any potential default or event of default, as
defined in the Credit Agreement, occurs or would result from the cash distribution. The indenture
relating to our 6.25% senior notes prohibits us from making cash distributions under certain
circumstances.
Within 45 days after the end of each quarter, we distribute all of our available cash (as defined
in our partnership agreement) to unitholders of record on the applicable record date. The amount
of available cash generally is all cash on hand at the end of the quarter: less the amount of cash
reserves established by our general partner to provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments, or other agreements; or provide funds for
distributions to our unitholders and to our general partner for any one or more of the next four
quarters; plus all cash on hand on the date of determination of available cash for the quarter
resulting from working capital borrowings made after the end of the quarter. Working capital
borrowings are generally borrowings that are made under our revolving credit facility and in all
cases are used solely for working capital purposes or to pay distributions to partners.
Upon the closing of our initial public offering, Holly received 7,000,000 subordinated units.
During the subordination period, the common units have the right to receive distributions of
available cash from operating surplus in an amount equal to the minimum quarterly distribution of
$0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the
common units from prior quarters, before any distributions of available cash from operating surplus
may be made on the subordinated units. The purpose of the subordinated units is to increase the
likelihood that during the subordination period there will be available cash to be distributed on
the common units. The subordination period extends until the first day of any quarter beginning
after June 30, 2009 that certain tests based on our exceeding minimum quarterly distributions are
met. That period is currently expected to end as of July 1, 2009.
-38-
We issued 937,500 of our Class B subordinated units in connection with the Alon transaction in
2005. The Class B subordinated units issued to Alon vote as a single class and rank equally with
our existing subordinated units. There is a subordination period with respect to the Class B
subordinated units with generally similar provisions to the subordinated units held by Holly,
except that the subordination period will end on the last day of any quarter ending on or after
March 31, 2010 if Alon has not defaulted on its minimum volume commitment payment obligations for
the three consecutive, non-overlapping four quarter periods immediately preceding that date,
subject to certain grace periods. If Holly is removed as the general partner without cause, the
subordination period for the Class B subordinated units may end before March 31, 2010.
We make distributions of available cash from operating surplus for any quarter during any
subordination period in the following manner: first, 98% to the common unitholders, pro rata, and
2% to the general partner, until we distribute for each outstanding common unit an amount equal to
the minimum quarterly distribution for that quarter; second, 98% to the common unitholders, pro
rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount
equal to any arrearages in payment of the minimum quarterly distribution on the common units for
any prior quarters during the subordination period; third, 98% to the subordinated unitholders, pro
rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal
to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the
minimum quarterly distributions is distributed to the unitholders and the general partner based on
the percentages below.
The 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 shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage Interest in |
|
|
Total Quarterly Distribution |
|
Distributions |
|
|
Target Amount |
|
Unitholders |
|
General Partner |
Minimum Quarterly Distribution |
|
$ |
0.50 |
|
|
|
98 |
% |
|
|
2 |
% |
First Target Distribution |
|
Up to $0.55 |
|
|
98 |
% |
|
|
2 |
% |
Second Target Distribution |
|
above $0.55 up to $0.625 |
|
|
85 |
% |
|
|
15 |
% |
Third Target distribution |
|
above $0.625 up to $0.75 |
|
|
75 |
% |
|
|
25 |
% |
Thereafter |
|
Above $0.75 |
|
|
50 |
% |
|
|
50 |
% |
-39-
Item 6. Selected Financial Data
The following table shows selected financial information for HEP. This table should be read in
conjunction with Item 7, Managements Discussion and Analysis of Financial Condition and Results
of Operations and the consolidated financial statements of HEP and related notes thereto included
elsewhere in this Form 10-K. See Historical Results of Operations below for a description of
factors affecting the comparability of our financial information for 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined |
|
|
Successor |
|
|
Predecessor |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 13, 2004 |
|
|
January 1, 2004 |
|
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Through |
|
|
Through |
|
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
July 12, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004(1) |
|
|
2004 |
|
|
2004 |
|
|
|
(In thousands, except per unit data) |
|
Statement Of Income Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
118,088 |
|
|
$ |
105,407 |
|
|
$ |
89,194 |
|
|
$ |
80,120 |
|
|
$ |
67,766 |
|
|
$ |
28,182 |
|
|
$ |
39,584 |
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
41,270 |
|
|
|
32,911 |
|
|
|
28,630 |
|
|
|
25,332 |
|
|
|
23,641 |
|
|
|
10,104 |
|
|
|
13,537 |
|
Depreciation and amortization |
|
|
22,889 |
|
|
|
14,382 |
|
|
|
15,330 |
|
|
|
14,201 |
|
|
|
7,224 |
|
|
|
3,241 |
|
|
|
3,983 |
|
General and administrative |
|
|
6,377 |
|
|
|
5,043 |
|
|
|
4,854 |
|
|
|
4,047 |
|
|
|
1,860 |
|
|
|
1,859 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70,536 |
|
|
|
52,336 |
|
|
|
48,814 |
|
|
|
43,580 |
|
|
|
32,725 |
|
|
|
15,204 |
|
|
|
17,521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
47,552 |
|
|
|
53,071 |
|
|
|
40,380 |
|
|
|
36,540 |
|
|
|
35,041 |
|
|
|
12,978 |
|
|
|
22,063 |
|
|
Interest income |
|
|
159 |
|
|
|
533 |
|
|
|
899 |
|
|
|
649 |
|
|
|
144 |
|
|
|
65 |
|
|
|
79 |
|
Interest expense |
|
|
(21,763 |
) |
|
|
(13,289 |
) |
|
|
(13,056 |
) |
|
|
(9,633 |
) |
|
|
(697 |
) |
|
|
(697 |
) |
|
|
|
|
Gain on sale of assets |
|
|
36 |
|
|
|
298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income |
|
|
996 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interest in Rio Grande Pipeline
Company |
|
|
(1,278 |
) |
|
|
(1,067 |
) |
|
|
(680 |
) |
|
|
(740 |
) |
|
|
(1,994 |
) |
|
|
(956 |
) |
|
|
(1,038 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,850 |
) |
|
|
(13,525 |
) |
|
|
(12,837 |
) |
|
|
(9,724 |
) |
|
|
(2,547 |
) |
|
|
(1,588 |
) |
|
|
(959 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
25,702 |
|
|
|
39,546 |
|
|
|
27,543 |
|
|
|
26,816 |
|
|
|
32,494 |
|
|
|
11,390 |
|
|
|
21,104 |
|
|
State income tax |
|
|
(335 |
) |
|
|
(275 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
25,367 |
|
|
|
39,271 |
|
|
|
27,543 |
|
|
|
26,816 |
|
|
|
32,494 |
|
|
|
11,390 |
|
|
|
21,104 |
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Predecessor |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,104 |
|
|
|
|
|
|
|
21,104 |
|
General partner interest in net income,
including incentive
distributions(2) |
|
|
3,543 |
|
|
|
2,932 |
|
|
|
1,710 |
|
|
|
721 |
|
|
|
228 |
|
|
|
228 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
21,824 |
|
|
$ |
36,339 |
|
|
$ |
25,833 |
|
|
$ |
26,095 |
|
|
$ |
11,162 |
|
|
$ |
11,162 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit basic
and diluted(2) |
|
$ |
1.34 |
|
|
$ |
2.26 |
|
|
$ |
1.60 |
|
|
$ |
1.70 |
|
|
|
|
|
|
$ |
0.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions declared per unit
applicable to limited partners |
|
$ |
2.96 |
|
|
$ |
2.785 |
|
|
$ |
2.585 |
|
|
$ |
2.225 |
|
|
|
|
|
|
$ |
0.435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA (3) |
|
$ |
70,195 |
|
|
$ |
66,684 |
|
|
$ |
55,030 |
|
|
$ |
50,001 |
|
|
$ |
40,271 |
|
|
$ |
15,263 |
|
|
$ |
25,008 |
|
Distributable cash flow(4) |
|
$ |
60,365 |
|
|
$ |
51,012 |
|
|
$ |
47,219 |
|
|
$ |
42,451 |
|
|
$ |
38,687 |
|
|
$ |
14,492 |
|
|
$ |
24,195 |
|
Cash flows from operating activities |
|
$ |
63,651 |
|
|
$ |
59,056 |
|
|
$ |
45,853 |
|
|
$ |
42,628 |
|
|
$ |
15,867 |
|
|
$ |
15,371 |
|
|
$ |
496 |
|
Cash flows from investing activities |
|
$ |
(213,267 |
) |
|
$ |
(9,632 |
) |
|
$ |
(9,107 |
) |
|
$ |
(131,795 |
) |
|
$ |
(2,977 |
) |
|
$ |
(305 |
) |
|
$ |
(2,672 |
) |
Cash flows from financing activities |
|
$ |
144,564 |
|
|
$ |
(50,658 |
) |
|
$ |
(45,774 |
) |
|
$ |
90,646 |
|
|
$ |
(480 |
) |
|
$ |
1,770 |
|
|
$ |
(2,250 |
) |
Maintenance capital expenditures (5) |
|
$ |
3,133 |
|
|
$ |
1,863 |
|
|
$ |
1,095 |
|
|
$ |
364 |
|
|
$ |
1,197 |
|
|
$ |
305 |
|
|
$ |
892 |
|
Expansion capital expenditures |
|
|
39,170 |
|
|
|
8,094 |
|
|
|
8,012 |
|
|
|
3,519 |
|
|
|
1,780 |
|
|
|
|
|
|
|
1,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
42,303 |
|
|
$ |
9,957 |
|
|
$ |
9,107 |
|
|
$ |
3,883 |
|
|
$ |
2,977 |
|
|
$ |
305 |
|
|
$ |
2,672 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment |
|
$ |
290,284 |
|
|
$ |
158,600 |
|
|
$ |
160,484 |
|
|
$ |
162,298 |
|
|
$ |
74,626 |
|
|
$ |
74,626 |
|
|
$ |
95,337 |
|
Total assets |
|
$ |
439,688 |
|
|
$ |
238,904 |
|
|
$ |
245,771 |
|
|
$ |
254,775 |
|
|
$ |
103,758 |
|
|
$ |
103,758 |
|
|
$ |
156,373 |
|
Long-term debt |
|
$ |
355,793 |
|
|
$ |
181,435 |
|
|
$ |
180,660 |
|
|
$ |
180,737 |
|
|
$ |
25,000 |
|
|
$ |
25,000 |
|
|
$ |
|
|
Total liabilities |
|
$ |
431,568 |
|
|
$ |
200,348 |
|
|
$ |
198,582 |
|
|
$ |
190,962 |
|
|
$ |
28,998 |
|
|
$ |
28,998 |
|
|
$ |
53,146 |
|
Net partners equity (deficit) (6) |
|
$ |
(2,098 |
) |
|
$ |
27,816 |
|
|
$ |
36,226 |
|
|
$ |
52,060 |
|
|
$ |
61,528 |
|
|
$ |
61,528 |
|
|
$ |
89,964 |
|
-40-
|
|
|
(1) |
|
Combined results for the year ended December 31, 2004 is not a calculation based upon
U.S. generally accepted accounting principles (GAAP), and is presented here to provide
investors with additional information for comparing year-over-year information. |
|
(2) |
|
Net income is allocated between limited partners and the general partner interest in
accordance with the provisions of the partnership agreement. Net income allocated to the
general partner includes any incentive distributions declared in the period. The net
income applicable to the limited partners is divided by the weighted average limited
partner units outstanding in computing the net income per unit applicable to limited
partners. |
|
(3) |
|
Earnings before interest, taxes, depreciation and amortization (EBITDA) is calculated
as net income plus (i) interest expense net of interest income, (ii) state income tax and
(iii) depreciation and amortization. EBITDA is not a calculation based upon GAAP.
However, the amounts included in the EBITDA calculation are derived from amounts included
in our consolidated financial statements. 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 is also used by our management for internal
analysis and as a basis for compliance with financial covenants. |
|
|
|
Set forth below is our calculation of EBITDA. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined |
|
|
Successor |
|
|
Predecessor |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 13, 2004 |
|
|
January 1, 2004 |
|
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Through |
|
|
Through |
|
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
July 12, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2004 |
|
|
2004 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
25,367 |
|
|
$ |
39,271 |
|
|
$ |
27,543 |
|
|
$ |
26,816 |
|
|
$ |
32,494 |
|
|
$ |
11,390 |
|
|
$ |
21,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add interest expense |
|
|
18,479 |
|
|
|
12,281 |
|
|
|
12,088 |
|
|
|
8,848 |
|
|
|
531 |
|
|
|
531 |
|
|
|
|
|
Add amortization of discount and
deferred debt issuance costs |
|
|
1,002 |
|
|
|
1,008 |
|
|
|
968 |
|
|
|
785 |
|
|
|
166 |
|
|
|
166 |
|
|
|
|
|
Change in fair value interest
rate swaps |
|
|
2,282 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtract interest income |
|
|
(159 |
) |
|
|
(533 |
) |
|
|
(899 |
) |
|
|
(649 |
) |
|
|
(144 |
) |
|
|
(65 |
) |
|
|
(79 |
) |
Add state income tax |
|
|
335 |
|
|
|
275 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add depreciation and amortization |
|
|
22,889 |
|
|
|
14,382 |
|
|
|
15,330 |
|
|
|
14,201 |
|
|
|
7,224 |
|
|
|
3,241 |
|
|
|
3,983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
|
$ |
70,195 |
|
|
$ |
66,684 |
|
|
$ |
55,030 |
|
|
$ |
50,001 |
|
|
$ |
40,271 |
|
|
$ |
15,263 |
|
|
$ |
25,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4) |
|
Distributable cash flow is not a calculation based upon GAAP. However, the amounts
included in the calculation are derived from amounts separately presented in our
consolidated financial statements, with the exception of 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. We believe that this measure provides
investors an enhanced perspective of the operating performance of our assets and the cash
our business is generating. |
-41-
|
|
|
|
|
Set forth below is our calculation of distributable cash flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined |
|
|
Successor |
|
|
Predecessor |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 13, 2004 |
|
|
January 1, 2004 |
|
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Through |
|
|
Through |
|
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
July 12, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2004 |
|
|
2004 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
25,367 |
|
|
$ |
39,271 |
|
|
$ |
27,543 |
|
|
$ |
26,816 |
|
|
$ |
32,494 |
|
|
$ |
11,390 |
|
|
$ |
21,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add amortization of discount and
deferred debt issuance costs |
|
|
1,002 |
|
|
|
1,008 |
|
|
|
968 |
|
|
|
785 |
|
|
|
166 |
|
|
|
166 |
|
|
|
|
|
Add change in fair value
interest rate swaps |
|
|
2,282 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add depreciation and amortization |
|
|
22,889 |
|
|
|
14,382 |
|
|
|
15,330 |
|
|
|
14,201 |
|
|
|
7,224 |
|
|
|
3,241 |
|
|
|
3,983 |
|
Add (subtract) increase
(decrease) in deferred revenue |
|
|
11,958 |
|
|
|
(1,786 |
) |
|
|
4,473 |
|
|
|
1,013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtract maintenance capital
expenditures(5) |
|
|
(3,133 |
) |
|
|
(1,863 |
) |
|
|
(1,095 |
) |
|
|
(364 |
) |
|
|
(1,197 |
) |
|
|
(305 |
) |
|
|
(892 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow |
|
$ |
60,365 |
|
|
$ |
51,012 |
|
|
$ |
47,219 |
|
|
$ |
42,451 |
|
|
$ |
38,687 |
|
|
$ |
14,492 |
|
|
$ |
24,195 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5) |
|
Maintenance capital expenditures represent capital expenditures to replace partially
or fully depreciated assets in order to maintain the 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, and safety and
to address environmental regulations. |
|
(6) |
|
As a master limited partnership, we distribute our available cash, which historically
has exceeded our net income because depreciation and amortization expense represents a
non-cash charge against income. The result is a decline in partners equity since our
regular quarterly distributions have exceeded our quarterly net income. Additionally, if
the assets transferred to us upon our initial public offering in 2004 and the intermediate
pipelines purchased from Holly in 2005 had been acquired from third parties, our
acquisition cost in excess of Hollys basis in the transferred assets of $157.3 million
would have been recorded as increases to our properties and equipment and intangible assets
instead of reductions to our partners equity. |
Historical Results of Operations
Prior to the commencement of HEP operations on July 13, 2004, our historical financial data does
not reflect any general and administrative expenses as Holly did not historically allocate any of
its general and administrative expenses to its pipelines and terminals. Our historical results of
operations prior to July 13, 2004 include costs associated with crude oil and intermediate product
pipelines, which were not contributed to our partnership.
NPL constitutes HEPs predecessor. The transfer of ownership of assets from NPL to HEP on July 13,
2004 represented a reorganization of entities under common control and was recorded at NPLs
historical cost. Accordingly, our historical results of operations include the results of NPL
prior to the transfer to HEP.
-42-
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
This Item 7, including but not limited to the sections on Liquidity and Capital Resources,
contains forward-looking statements. See Forward-Looking Statements at the beginning of Part I.
In this document, the words we, our, ours and us refer to HEP and its consolidated
subsidiaries or to HEP or an individual subsidiary and not to any other person.
OVERVIEW
HEP is a Delaware limited partnership. We own and operate substantially all of the petroleum
product and crude oil pipeline and terminalling assets that support Hollys refining and marketing
operations in west Texas, New Mexico, Utah, Idaho and Arizona and a 70% interest in Rio Grande.
Holly currently owns a 46% interest in us.
We operate a system of petroleum product and crude oil pipelines in Texas, New Mexico, Oklahoma and
Utah and distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho and Washington. 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 or terminal; therefore, we are not directly exposed to changes in
commodity prices.
On February 29, 2008, we acquired the Crude Pipelines and Tankage Assets from Holly for $180.0
million. The Crude Pipelines and Tankage Assets primarily consist of crude oil trunk lines and
gathering lines, product and crude oil pipelines and tankage that service Hollys Navajo and Woods
Cross Refineries and a leased jet fuel terminal. Please read Holly Crude Pipelines and Tankage
Transaction under Liquidity and Capital Resources for additional information on this
transaction.
Agreements with Holly Corporation and Alon
We serve Hollys refineries in New Mexico and Utah under three 15-year pipeline, terminal and
tankage agreements. The substantial majority of our business is devoted to providing
transportation, storage and terminalling services to Holly.
We have an agreement, the Holly PTA, that relates to the pipelines and terminals contributed by
Holly to us at the time of our initial public offering in 2004 and expires in 2019. Our second
agreement, the Holly IPA, relates to the Intermediate Pipelines acquired from Holly in July 2005
and expires in 2020. Our third agreement, the Holly CPTA, relates to the Crude Pipelines and
Tankage Assets acquired from Holly as discussed above and expires in February 2023.
Under these agreements, Holly agreed to transport and store volumes of refined product and crude
oil on our pipelines and terminal and tankage facilities that result in minimum annual payments to
us. These minimum annual payments or revenues will be adjusted each year at a percentage change
equal to the change in the PPI but will not decrease as a result of a decrease in the PPI. Under
these agreements, the agreed upon tariff rates are adjusted each year on July 1 at a rate equal to
the percentage change in the PPI or FERC index, but generally will not decrease as a result of a
decrease in the PPI or FERC index. The FERC index is the change in the PPI plus a FERC adjustment
factor which is reviewed periodically.
We also have a 15-year 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 results in a minimum level of annual revenue. The agreed upon tariff rates
are increased or decreased annually at a rate equal to the percentage change in PPI, but not below
the initial tariff rate.
-43-
At December 31, 2008, contractual minimums under our long-term service agreements are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum
Annualized |
|
|
|
|
|
|
|
|
|
Commitment |
|
|
|
|
|
|
|
Agreement |
|
(In millions) |
|
|
Year of Maturity |
|
Contract Type |
|
Holly PTA |
|
$ |
41.2 |
|
|
|
2019 |
|
|
Minimum revenue commitment |
Holly IPA |
|
|
13.3 |
|
|
|
2020 |
|
|
Minimum revenue commitment |
Holly CPTA |
|
|
26.8 |
|
|
|
2023 |
|
|
Minimum revenue commitment |
Alon PTA |
|
|
22.0 |
|
|
|
2020 |
|
|
Minimum volume commitment |
Alon capacity lease |
|
|
6.8 |
|
|
Various |
|
Capacity lease |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
110.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We depend on our agreements with Holly and Alon for the majority of our revenues. A significant
reduction in revenues under these agreements would have a material adverse effect on our results of
operations.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we
have agreed to expand our refined products pipeline system between Artesia, New Mexico and El Paso,
Texas (the South System). The expansion of the South System includes replacing 85 miles of
8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso
Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and
Phoenix, Arizona and making related modifications. The cost of this project is estimated to be
$48.3 million. Currently, we expect to complete the majority of this project in early 2009.
Under certain provisions of the Omnibus Agreement that we entered into with Holly in July 2004 and
expires in 2019, we pay Holly an annual administrative fee for the provision by Holly or its
affiliates of various general and administrative services to us. Effective March 1, 2008, the
annual fee was increased from $2.1 million to $2.3 million to cover additional general and
administrative services attributable to the operations of our Crude Pipelines and Tankage Assets.
This fee does not include the salaries of pipeline and terminal personnel or the cost of their
employee benefits, which are separately charged to us by Holly. We also reimburse Holly and its
affiliates for direct expenses they incur on our behalf.
Please read Agreements with Holly under Item 1, Business for additional information on these
agreements with Holly and Alon.
-44-
RESULTS OF OPERATIONS
The following tables present our operating income, volume information and cash flow summary
information for the years ended December 31, 2008, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
|
|
|
December 31, |
|
|
Change from |
|
|
|
2008 |
|
|
2007 |
|
|
2007 |
|
|
|
(In thousands, except per unit data) |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
$ |
40,446 |
|
|
$ |
36,281 |
|
|
$ |
4,165 |
|
Affiliates intermediate pipelines |
|
|
11,917 |
|
|
|
13,731 |
|
|
|
(1,814 |
) |
Affiliates crude pipelines |
|
|
22,380 |
|
|
|
|
|
|
|
22,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74,743 |
|
|
|
50,012 |
|
|
|
24,731 |
|
Third parties refined product pipelines |
|
|
28,580 |
|
|
|
36,271 |
|
|
|
(7,691 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
103,323 |
|
|
|
86,283 |
|
|
|
17,040 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and truck loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
10,297 |
|
|
|
10,949 |
|
|
|
(652 |
) |
Third parties |
|
|
4,468 |
|
|
|
5,427 |
|
|
|
(959 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
14,765 |
|
|
|
16,376 |
|
|
|
(1,611 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other affiliates |
|
|
|
|
|
|
2,748 |
|
|
|
(2,748 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
118,088 |
|
|
|
105,407 |
|
|
|
12,681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
41,270 |
|
|
|
32,911 |
|
|
|
8,359 |
|
Depreciation and amortization |
|
|
22,889 |
|
|
|
14,382 |
|
|
|
8,507 |
|
General and administrative |
|
|
6,377 |
|
|
|
5,043 |
|
|
|
1,334 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70,536 |
|
|
|
52,336 |
|
|
|
18,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
47,552 |
|
|
|
53,071 |
|
|
|
(5,519 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
159 |
|
|
|
533 |
|
|
|
(374 |
) |
Interest expense, including amortization |
|
|
(21,763 |
) |
|
|
(13,289 |
) |
|
|
(8,474 |
) |
Gain on sale of assets |
|
|
36 |
|
|
|
298 |
|
|
|
(262 |
) |
Other income |
|
|
996 |
|
|
|
|
|
|
|
996 |
|
Minority interest in Rio Grande Pipeline Company |
|
|
(1,278 |
) |
|
|
(1,067 |
) |
|
|
(211 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,850 |
) |
|
|
(13,525 |
) |
|
|
(8,325 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
25,702 |
|
|
|
39,546 |
|
|
|
(13,844 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
(335 |
) |
|
|
(275 |
) |
|
|
(60 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
25,367 |
|
|
|
39,271 |
|
|
|
(13,904 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Less general partner interest in net income, including incentive
distributions (1) |
|
|
3,543 |
|
|
|
2,932 |
|
|
|
611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
21,824 |
|
|
$ |
36,339 |
|
|
$ |
(14,515 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per unit applicable to limited partners (1) |
|
$ |
1.34 |
|
|
$ |
2.26 |
|
|
$ |
(0.92 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partners units outstanding |
|
|
16,291 |
|
|
|
16,108 |
|
|
|
183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(2) |
|
$ |
70,195 |
|
|
$ |
66,684 |
|
|
$ |
3,511 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow (3) |
|
$ |
60,365 |
|
|
$ |
51,012 |
|
|
$ |
9,353 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (bpd)(4) |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
|
83,203 |
|
|
|
77,441 |
|
|
|
5,762 |
|
Affiliates intermediate pipelines |
|
|
58,855 |
|
|
|
65,006 |
|
|
|
(6,151 |
) |
Affiliates crude pipelines |
|
|
111,426 |
|
|
|
|
|
|
|
111,426 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
253,484 |
|
|
|
142,447 |
|
|
|
111,037 |
|
Third parties refined product pipelines |
|
|
38,330 |
|
|
|
62,720 |
|
|
|
(24,390 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
291,814 |
|
|
|
205,167 |
|
|
|
86,647 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and truck loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
109,539 |
|
|
|
119,910 |
|
|
|
(10,371 |
) |
Third parties |
|
|
32,737 |
|
|
|
45,457 |
|
|
|
(12,720 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
142,276 |
|
|
|
165,367 |
|
|
|
(23,091 |
) |
|
|
|
|
|
|
|
|
|
|
Total for pipelines and terminal assets (bpd) |
|
|
434,090 |
|
|
|
370,534 |
|
|
|
63,556 |
|
|
|
|
|
|
|
|
|
|
|
-45-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
|
|
|
December 31, |
|
|
Change from |
|
|
2007 |
|
|
2006 |
|
|
2006 |
|
|
|
(In thousands, except per unit data) |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
$ |
36,281 |
|
|
$ |
31,723 |
|
|
$ |
4,558 |
|
Affiliates intermediate pipelines |
|
|
13,731 |
|
|
|
10,733 |
|
|
|
2,998 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,012 |
|
|
|
42,456 |
|
|
|
7,556 |
|
Third parties refined product pipelines |
|
|
36,271 |
|
|
|
31,685 |
|
|
|
4,586 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86,283 |
|
|
|
74,141 |
|
|
|
12,142 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and truck loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
10,949 |
|
|
|
10,422 |
|
|
|
527 |
|
Third parties |
|
|
5,427 |
|
|
|
4,631 |
|
|
|
796 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,376 |
|
|
|
15,053 |
|
|
|
1,323 |
|
Other affiliates |
|
|
2,748 |
|
|
|
|
|
|
|
2,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
105,407 |
|
|
|
89,194 |
|
|
|
16,213 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
32,911 |
|
|
|
28,630 |
|
|
|
4,281 |
|
Depreciation and amortization |
|
|
14,382 |
|
|
|
15,330 |
|
|
|
(948 |
) |
General and administrative |
|
|
5,043 |
|
|
|
4,854 |
|
|
|
189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52,336 |
|
|
|
48,814 |
|
|
|
3,522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
53,071 |
|
|
|
40,380 |
|
|
|
12,691 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
533 |
|
|
|
899 |
|
|
|
(366 |
) |
Interest expense, including amortization |
|
|
(13,289 |
) |
|
|
(13,056 |
) |
|
|
(233 |
) |
Gain on sale of assets |
|
|
298 |
|
|
|
|
|
|
|
298 |
|
Minority interest in Rio Grande Pipeline Company |
|
|
(1,067 |
) |
|
|
(680 |
) |
|
|
(387 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,525 |
) |
|
|
(12,837 |
) |
|
|
(688 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
39,546 |
|
|
|
27,543 |
|
|
|
12,003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
(275 |
) |
|
|
|
|
|
|
(275 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
39,271 |
|
|
|
27,543 |
|
|
|
11,728 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less general partner interest in net income, including incentive
distributions (1) |
|
|
2,932 |
|
|
|
1,710 |
|
|
|
1,222 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
36,339 |
|
|
$ |
25,833 |
|
|
$ |
10,506 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per unit applicable to limited partners (1) |
|
$ |
2.26 |
|
|
$ |
1.60 |
|
|
$ |
0.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partners units outstanding |
|
|
16,108 |
|
|
|
16,108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(2) |
|
$ |
66,684 |
|
|
$ |
55,030 |
|
|
$ |
11,654 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow (3) |
|
$ |
51,012 |
|
|
$ |
47,219 |
|
|
$ |
3,793 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (bpd) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
|
77,441 |
|
|
|
69,271 |
|
|
|
8,170 |
|
Affiliates intermediate pipelines |
|
|
65,006 |
|
|
|
57,658 |
|
|
|
7,348 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
142,447 |
|
|
|
126,929 |
|
|
|
15,518 |
|
Third parties refined product pipelines |
|
|
62,720 |
|
|
|
62,655 |
|
|
|
65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
205,167 |
|
|
|
189,584 |
|
|
|
15,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and truck loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
119,910 |
|
|
|
118,202 |
|
|
|
1,708 |
|
Third parties |
|
|
45,457 |
|
|
|
43,285 |
|
|
|
2,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
165,367 |
|
|
|
161,487 |
|
|
|
3,880 |
|
|
|
|
|
|
|
|
|
|
|
Total for pipelines and terminal assets (bpd) |
|
|
370,534 |
|
|
|
351,071 |
|
|
|
19,463 |
|
|
|
|
|
|
|
|
|
|
|
(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 any incentive distributions declared in the period. The net income
applicable to the limited partners is divided by the weighted average limited partner units
outstanding in computing the net income per unit applicable to limited partners. |
-46-
(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 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 is also used by our management for internal analysis and as a basis for
compliance with financial covenants. See our calculation of EBITDA
under Item 6, Select Financial Data. |
(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 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. We
believe that this measure provides investors an enhanced perspective of the operating
performance of our assets and the cash our business is generating. See our calculation of
distributable cash flow under Item 6, Select Financial Data. |
(4) |
|
The amounts reported for the year ended December 31, 2008 include volumes transported on the
crude pipelines for the period from March 1, 2008 through December 31, 2008 only. Volumes
shipped during the months of March through December 2008 averaged 133.3 thousand barrels per
day (mbpd). For the year ended December 31, 2008, crude pipeline volumes are based on
volumes for the months of March through December, averaged over the 366 days in 2008. Under
the Holly CPTA, fees are based on volumes transported on each pipeline component comprising
the crude pipeline system (the crude oil gathering pipelines and the crude oil trunk lines).
Accordingly, volumes transported on the crude pipelines represent the sum of volumes
transported on both pipeline components. In cases where volumes are transported over both
components of the crude pipeline system, such volumes are reflected twice in the total crude
oil pipeline volumes. |
Results of Operations Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
Summary
Net income for the year ended December 31, 2008 was $25.4 million, a $13.9 million decrease
compared to the year ended December 31, 2007. This decrease in overall earnings was due
principally to the effects of limited production at Alons Big Spring Refinery resulting from an
explosion and fire in February, a decrease in previously deferred revenue realized and an increase
in operating costs and expenses and interest expense. These factors were partially offset by
revenues attributable to our crude pipeline assets acquired in the first quarter of 2008, the
effect of the annual tariff rate increases and an increase in affiliate refined product shipments.
Revenues of $15.7 million relating to deficiency payments associated with certain guaranteed
shipping contracts was deferred during the year ended December 31, 2008. Such deferred revenue
will be recognized in 2009 either as payment for shipments in excess of guaranteed levels or when
shipping rights expire unused after a twelve-month period.
On February 18, 2008, Alon experienced an explosion and fire at its Big Spring refinery that
resulted in the shutdown of production. In early April, Alon reopened its Big Spring refinery and
resumed production at about one-half of refining capacity until production was restored in late
September and later increased to full capacity during the fourth quarter. Lost production and
reduced operations attributable to this incident resulted in a decrease in third party shipments on
our refined product pipelines during the first nine months of 2008. Under our pipelines and
terminals agreement with Alon, Alon has committed to a level of product shipments that generally
results in a minimum level of annual revenue. If Alon does not
-47-
meet their minimum commitments, we bill them quarterly an amount related to such shortfalls.
Although these shortfall billings are required to be recorded as deferred revenues, such shortfall
billings are included in our distributable cash flow as they occur.
Revenues
Total revenues for the year ended December 31, 2008 were $118.1 million, a $12.7 million increase
compared to the year ended December 31, 2007. This increase was due principally to revenues
attributable to our crude pipeline assets acquired in the first quarter of 2008, an increase in
affiliate refined product shipments and the effect of annual tariff rate increases. These
increases were partially offset by a decrease in third party shipments, a decrease in shipments on
our intermediate pipeline system and a net decrease in previously deferred revenue realized. Also
affecting our revenue comparison was 2007 third quarter revenue of $2.7 million related to our sale
of inventory of accumulated overages of refined products at our terminals. There was no comparable
revenue for the year ended December 31, 2008.
Revenues from our refined product pipelines were $69.0 million, a decrease of $3.5 million compared
to the year ended December 31, 2007. This decrease was due to a decline in third party shipments
as a result of reduced production and downtime following an explosion at Alons Big Spring refinery
during the first quarter and a $0.5 million decrease in previously deferred revenue realized.
These decreases were partially offset by an increase in affiliate shipments and the effect of the
annual tariff rate increase on refined product shipments. Overall shipments on our refined product
pipeline system decreased to an average of 121.5 mbpd compared to 140.2 mbpd for the same period
last year.
Revenues from our intermediate pipelines were $11.9 million, a decrease of $1.8 million compared to
the year ended December 31, 2007. This decrease was due to the effects of downtime at Hollys
Navajo Refinery during the second quarter of 2008 and a $1.2 million decrease in previously
deferred revenue realized. These decreases were partially offset by the effect of the annual
tariff rate increase on intermediate pipeline shipments. Shipments on our intermediate product
pipeline system decreased to an average of 58.9 mbpd compared to 65.0 mbpd for the same period last
year.
Revenues from our crude pipelines were $22.4 million; shipments for the months of March through
December 2008 averaged 133.3 mbpd.
Revenues from terminal, tankage and truck loading rack fees were $14.8 million, a decrease of $1.6
million compared to the year ended December 31, 2007. This decrease is due principally to the
effects of downtime at Alons Big Spring Refinery during the first nine months of 2008 and downtime
at Hollys Navajo Refinery during the second quarter of 2008. Refined products terminalled in our
facilities decreased to an average of 142.3 mbpd compared to 165.4 mbpd for the same period last
year.
Other revenues for the year ended December 31, 2007 consisted of $2.7 million related to the sale
of inventory of accumulated terminal overages of refined product to Holly. There was no comparable
revenue for the year ended December 31, 2008.
Operations Expense
Operations expense for the year ended December 31, 2008 increased by $8.4 million compared to the
year ended December 31, 2007. This increase in expense was due principally to the operations of
our crude pipelines commencing March 1, 2008 and increased pipeline maintenance and payroll costs.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2008 increased by $8.5 million
compared to the year ended December 31, 2007, due principally to depreciation and amortization
attributable to our newly acquired crude pipelines, tankage assets and related transportation
agreement.
-48-
General and Administrative
General and administrative costs for the year ended December 31, 2008 increased by $1.3 million
compared to the year ended December 31, 2007, due principally to an increase professional fees and
equity based compensation expense.
Interest Expense
Interest expense for the year ended December 31, 2008 totaled $21.8 million, an increase of $8.5
million compared to the year ended December 31, 2007. This increase is due principally to interest
attributable to advances from our revolving credit agreement that were used to finance the purchase
of the Crude Pipelines and Tankage Assets in the first quarter as well as capital projects.
Additionally, interest expense for the year ended December 31, 2008 includes $2.3 million in
non-cash interest expense as a result of the application of fair value accounting to two of our
interest rate swap agreements. For the year ended December 31, 2008, our aggregate effective
interest rate was 5.6% compared to 7.2% for 2007.
Minority Interest in Earnings of Rio Grande
The minority interest related to the 30% of Rio Grande that we do not own reduced our income by
$1.3 for the year ended December 31, 2008 compared to $1.1 million for the year ended December 31,
2007.
State Income Tax
We recorded state income taxes of $0.3 million for each of the years ended December 31, 2008 and
2007 that are solely attributable to the Texas margin tax.
Results of Operations Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Summary
Net income for the year ended December 31, 2007 was $39.3 million, an $11.8 million increase
compared to the year ended December 31, 2006. The increase in overall earnings was due principally
to an increase in volumes transported on our pipeline systems, the effect of the annual tariff rate
increases on product shipments, the realization of certain previously deferred revenue and revenue
related to the sale of inventory of accumulated terminal overages of refined product to Holly,
partially offset by an increase in our operating costs and expenses. Revenues of $3.7 million
relating to deficiency payments associated with certain guaranteed shipping contracts was deferred
during the year ended December 31, 2007. Such deferred revenue was recognized in 2008 either as
payment for shipments in excess of guaranteed levels or when shipping rights expired unused after a
twelve-month period.
Revenues
Total revenues for the year ended December 31, 2007 were $105.4, a $16.2 million increase compared
to the year ended December 31, 2006. This increase was due principally to an increase in volumes
transported on our pipeline systems, the effect of annual tariff rate increases, an increase in
previously deferred revenue realized and revenue related to the sale of inventory of accumulated
terminal overages of refined product to Holly.
The increase in volumes transported on our pipeline systems for the year ended December 31, 2007
compared to 2006 was due principally to significant downtime at all of the refineries served by our
product distribution network in the second quarter of 2006. Refiners were generally required to
start producing ultra low sulfur diesel fuel (ULSD) by June 2006. To meet this requirement, many
refiners, including Hollys Navajo Refinery and Alons Big Spring Refinery, required downtime at
their refineries so that ULSD-associated projects could be brought on line. Additionally, Holly
completed an
expansion of the
-49-
Navajo Refinery during this period of downtime, which resulted in increased
refinery production and has contributed to increased volume shipments on our pipeline systems.
Revenues from our refined product pipelines were $72.6 million, an increase of $9.2 million
compared to the year ended December 31, 2006. This increase in refined product pipeline revenue
was due principally to an increase in volumes shipped on our refined product pipelines, the effect
of the annual tariff rate increase on refined product shipments and the realization of $3.1 million
of previously deferred revenue. Overall shipments on our refined product pipeline system increased
to an average of 140.2 mbpd compared to 131.9 mbpd for the year ended December 31, 2006.
Revenues from our intermediate pipelines were $13.7 million, an increase of $3.0 million compared
to the year ended December 31, 2006. This increase was due principally to an increase in volumes
shipped on our intermediate pipelines, the effect of the annual tariff rate increase on
intermediate pipeline shipments and a $1.4 million increase in previously deferred revenue
realized. Shipments on our intermediate product pipeline system increased to an average of 65.0
mbpd compared to 57.7 mbpd for the year ended December 31, 2006.
Revenues from terminal and truck loading rack service fees were $16.4 million, an increase of $1.3
million compared to the year ended December 31, 2006. This increase was due principally to an
increase in refined products terminalled in our facilities. Refined products terminalled in our
facilities increased to an average of 165.4 mbpd compared to 161.5 mbpd for the year ended December
31, 2006.
Other revenues for the year ended December 31, 2007 consisted of $2.7 million related to the sale
of inventory of accumulated terminal overages of refined product to Holly. These overages arose
from net product gains at our terminals from the beginning of 2005 through the third quarter of
2007. In the fourth quarter of 2007, we amended our pipelines and terminals agreement with Holly
to provide that, on a go-forward basis, such terminal overages of refined product belong to Holly.
There were no other revenues for the year ended December 31, 2006.
Operations Expense
Operations expense for the year ended December 31, 2007 increased $4.3 million compared to the year
ended December 31, 2006. This increase in expense was due principally to higher throughput
volumes, an increase in pipeline and terminal maintenance expense and an increase in the cost of
employees who perform services for us, including the addition of two new senior level executives.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2007 decreased by $0.9 million
compared to the year ended December 31, 2006, due principally to a reduction in amortization
expense, as a transportation agreement became fully amortized in April 2007.
General and Administrative
General and administrative costs for the year ended December 31, 2007 increased by $0.2 million
compared to the year ended December 31, 2006, due principally to an increase in equity-based
incentive compensation expense.
Interest Expense
Interest expense for the year ended December 31, 2007 totaled $13.3 million, an increase of $0.2
million from $13.1 million for the year ended December 31, 2006. For the year ended December 31,
2007, our aggregate effective interest rate was 7.2% compared to 7.1% for 2006.
Minority Interest in Earnings of Rio Grande
The minority interest related to the 30% of Rio Grande that we do not own reduced our income by
$1.1 for the year ended December 31, 2007 compared to $0.7 million for the year ended December 31,
2006.
-50-
State Income Tax
Effective January 1, 2007, the Texas margin tax applied to legal entities conducting business in
Texas, including previously non-taxable entities such as limited partnerships and limited liability
partnerships. As a result, we recorded $0.3 million in state income tax for the year ended
December 31, 2007 that is solely attributable to the Texas margin tax. There was no comparable
state income tax for the year ended December 31, 2006.
LIQUIDITY AND CAPITAL RESOURCES
Overview
In February 2008, we amended our $100.0 million senior secured revolving credit agreement expiring
in August 2011 to increase the size from $100.0 million to $300.0 million, which we used to finance
the $171.0 million cash portion of the consideration paid for the Crude Pipelines and Tankage
Assets acquired from Holly. As of December 31, 2008, we had $200.0 million outstanding under the
Credit Agreement. The Credit Agreement is available to fund capital expenditures, acquisitions,
and working capital and for general partnership purposes. Advances under the Credit Agreement that
are either designated for working capital or have been used as interim financing to fund capital
expenditures are classified as short-term liabilities. Other advances under the Credit Agreement
are classified as long-term liabilities. During the year ended December 31, 2008, we received net
advances totaling $29.0 million under the Credit Agreement that were used as interim financing for
capital expenditures.
Our senior notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25% (the
Senior Notes). The Senior Notes are unsecured and impose certain restrictive covenants,
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.
We renewed our shelf registration statement in 2008, under which we may offer from time to time
up to $1.0 billion of our securities, 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
our Credit Agreement will provide sufficient resources to meet our working capital liquidity needs
for the foreseeable future. With the current conditions in the credit and equity markets, there
may be limits on our ability to issue new debt or equity securities. Additionally, due to pricing
in the current debt and equity markets, we may not be able to issue new debt and equity securities
at acceptable pricing. As a result, our ability to fund certain of our planned capital
expenditures and other business opportunities may be limited.
In February, May, August and November 2008, we paid regular quarterly cash distributions of $0.725,
$0.735, $0.745 and $0.755, respectively, on all units, an aggregate amount of $52.4 million.
Included in these distributions was an aggregate of $3.1 million paid to the general partner as
incentive distributions, as the quarterly distributions per unit exceeded the target distribution
amount of $0.55.
Cash and cash equivalents decreased by $5.1 million during the year ended December 31, 2008. The
cash flows used for investing activities of $213.3 million, exceeded cash flows provided by
operating and financing activities of $63.7 million and $144.6, respectively. Working capital
decreased by $43.3 million due principally to $29.0 million in interim financing of capital
projects.
-51-
Cash Flows Operating Activities
Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
Cash flows from operating activities increased by $4.6 million from $59.1 million for the year
ended December 31, 2007 to $63.7 million for the year ended December 31, 2008. This increase is
due principally to $20.8 million in additional cash collections from our major customers, resulting
principally from increased revenues and shortfall billings, partially offset by miscellaneous
year-over-year changes in collections and payments.
Our major shippers are obligated to make deficiency payments to us if they do not meet their
minimum volume shipping obligations. Certain of these shippers then have the right to recapture
these amounts if future volumes exceed minimum levels. For the year ended December 31, 2008, we
received cash payments of $14.3 million related to shortfall billings under these commitments. We
billed $3.8 million during the year ended December 31, 2007 related to shortfalls that occurred in
this period that expired without recapture and was recognized as revenue during the year ended
December 31, 2008. Another $1.8 million is included in our accounts receivable at December 31,
2008 related to shortfalls that occurred in the fourth quarter of 2008.
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Cash flows from operating activities increased by $13.2 million from $45.9 million for the year
ended December 31, 2006 to $59.1 million for the year ended December 31, 2007. This increase is
due principally to $14.8 million in additional cash collections from our major customers, resulting
principally from increased revenues and shortfall billings, partially offset by miscellaneous
year-over-year changes in collections and payments.
For the year ended December 31, 2007, we received cash payments of $4.6 million related to
shortfall billings. We billed $5.5 million during the year ended December 31, 2006 related to
shortfalls that occurred in this period that expired without recapture and was recognized as
revenue in the year ended December 31, 2007. Another $0.4 million is included in our accounts
receivable at December 31, 2007 related to shortfalls that occurred in the fourth quarter of 2007.
Cash Flows Investing Activities
Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
Cash flows used for investing activities increased by $203.7 million from $9.6 million for the year
ended December 31, 2007 to $213.3 million for the year ended December 31, 2008. In connection with
our purchase of the Crude Pipelines and Tankage Assets on February 29, 2008, we paid cash
consideration to Holly of $171.0 million. Additions to properties and equipment for the year ended
December 31, 2008 was $42.3 million, an increase of $32.3 million from $10.0 million for the year
ended December 31, 2007.
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Cash flows used for investing activities increased by $0.5 million from $9.1 million for the year
ended December 31, 2006 to $9.6 million for the year ended December 31, 2007. Additions to
properties and equipment for the year ended December 31, 2007 was $10.0 million, an increase of
$0.9 million from $9.1 million for the year ended December 31, 2006. During the year ended
December 31, 2007, we also received cash proceeds of $0.3 million related to the sale of certain
assets.
Cash Flows Financing Activities
Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
Cash flows provided by financing activities increased by $195.3 million from $50.7 million used for
financing activities for the year ended December 31, 2007 to $144.6 million provided by financing
activities for the ended December 31, 2008. During the year ended December 31, 2008, we received
net advances of $200.0 million under the Credit Agreement of which $171.0 million was used to
finance the cash portion of the consideration paid to acquire the Crude Pipelines and Tankage
Assets on February 29, 2008. During the year ended December 31, 2008, we paid cash distributions
on all units and the
-52-
general partner interest in the aggregate amount of $52.4 million, an increase of $4.4 million from
$48.0 million for the year ended December 31, 2007. Cash distributions paid to the minority
interest owner in Rio Grande was $1.8 million for the year ended December 31, 2008, an increase of
$0.6 million from $1.3 million for the year ended December 31, 2007. Cash paid for the purchase of
our common units for restricted grants was $0.8 million for the year ended December 31, 2008, a
decrease of $0.3 million from $1.1 million for the year ended December 31, 2007. Also for the year
ended December 31, 2008, we paid $0.7 million in deferred financing costs that were attributable to
the amendment to our Credit Agreement.
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Cash flows used for financing activities increased by $4.9 million from $45.8 million for the year
ended December 31, 2006 to $50.7 million for the ended December 31, 2007. During the year ended
December 31, 2007, we paid cash distributions on all units and the general partner interest in the
aggregate amount of $48.0 million, an increase of $4.3 million from $43.7 million for the year
ended December 31, 2006. Cash distributions paid to the minority interest owner in Rio Grande was
$1.3 million for the year ended December 31, 2007, a decrease of $0.2 million from $1.5 million for
the year ended December 31, 2006. Cash paid for the purchase of our common units for restricted
grants was $1.1 million for the year ended December 31, 2007, an increase of $0.5 million from $0.6
million for the year ended December 31, 2006. Also for the year ended December 31, 2007, we paid
$0.3 million in deferred financing costs that were attributable to the amendment to our Credit
Agreement.
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 to 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 years capital budget
as well as, in certain cases, expenditures approved for capital projects in capital budgets for
prior years. The 2009 capital budget is comprised of $3.7 million for maintenance capital
expenditures and $2.2 million for expansion capital expenditures. Additionally, capital
expenditures planned in 2009 include approximately $43.0 million for capital projects approved in
prior years, most of which relate to the expansion of the South System and the joint venture with
Plains All American Pipeline, L.P. discussed below.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we
have agreed to expand our South System between Artesia, New Mexico and El Paso, Texas. The
expansion of the South System includes replacing 85 miles of 8-inch pipe with 12-inch pipe, adding
150,000 barrels of refined product storage at our El Paso Terminal, improving existing pumps,
adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making related
modifications. The cost of this project is estimated to be $48.3 million. We expect to complete
the majority of this project in early 2009.
In November 2007, we executed a definitive agreement with Plains to acquire a 25% joint venture
interest in a new 95-mile intrastate pipeline system now under construction by Plains for the
shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. Under the agreement, the
SLC Pipeline will be owned by a joint venture company that will be owned 75% by Plains and 25% by
us. We expect to purchase our 25% interest in the joint venture in March 2009 when the SLC
Pipeline is expected to become fully operational. The SLC Pipeline will allow various refiners in
the Salt Lake City area, including Hollys Woods Cross Refinery, to ship crude oil into the Salt
Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil from Wyoming
and Utah that is currently flowing on Plains Rocky Mountain Pipeline. The total cost of our
investment in the SLC Pipeline is expected to be $28.0 million,
-53-
including a $2.5 million finders fee that is payable to Holly upon the closing of our investment
in the SLC Pipeline.
On January 31, 2008, we entered into an option agreement with Holly, granting us an option to
purchase all of Hollys equity interests in a joint venture pipeline currently under construction.
The pipeline will be capable of transporting refined petroleum products from Salt Lake City, Utah
to Las Vegas, Nevada. Holly owns 75% of the equity interests in the UNEV Pipeline. Under this
agreement, we have an option to purchase Hollys equity interests in the UNEV Pipeline, effective
for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price
equal to Hollys 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 total cost of the pipeline project including terminals is expected to be $300.0
million. Hollys share of this cost is $225.0 million.
On July 17, 2008, Holly
announced the purchase of Musket Corporations Cedar City, Utah terminal and rail facilities that
will serve as part of the UNEV Pipelines Cedar City Terminal.
Hollys UNEV project is in the final stage of the Bureau of
Land Management permit process. Since it is anticipated that the
permit to proceed will now be received during the second quarter of
2009, Holly is currently evaluating whether to maintain the current
completion schedule for UNEV of early 2010 or whether from a
commercial perspective, it would be better to delay completion until
the fall of 2010.
Holly is currently working on a project to deliver additional crude oils to its Navajo Refinery,
including a 70-mile pipeline from Centurion Pipeline L.P.s Slaughter Station in west Texas to
Lovington, New Mexico, and a 65-mile pipeline from Lovington to Artesia, New Mexico. Under
provisions of the Omnibus Agreement with Holly we will have an option to
purchase Hollys investment in the project at a purchase price to be negotiated with Holly. The
projects will increase the pipeline capacity between Lovington and Artesia by 40,000 bpd. The cost
of the projects is expected to be $90.0 million and construction is currently expected to be
completed and the projects to become fully operational in the fourth quarter of 2009.
We are currently working on a capital improvement project that will provide increased flexibility
and capacity to our Intermediate Pipelines enabling us to accommodate increased volumes following
Hollys Navajo Refinery capacity expansion. This project is expected to be completed in mid 2009
at an estimated cost of $5.1 million.
Also, we are currently converting an existing 12-mile crude oil pipeline to a natural gas pipeline
at an estimated cost of $1.9 million scheduled for completion in early 2009.
We expect that our currently planned expenditures for maintenance capital as well as expenditures
for acquisitions and capital development projects such as the UNEV Pipeline, SLC Pipeline, South
System expansion and Holly crude oil projects described above will be funded with existing cash
balances, cash generated by operations, the sale of additional limited partner units, the issuance
of debt securities and advances under our $300.0 million senior secured revolving credit agreement
maturing August 2011, or a combination thereof. With the current conditions in the credit and
equity markets there may be limits on our ability to issue new debt or equity securities.
Additionally, due to pricing in the current 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 and Hollys crude oil project. We are not obligated to
purchase these assets nor are we subject to any fees or penalties if HEPs board of directors
decide not to proceed with either of these opportunities.
Credit Agreement
In February 2008, we amended our $100.0 million senior secured revolving credit agreement expiring
in August 2011 to increase the size from $100.0 million to $300.0 million, which we used to finance
the $171.0 million cash portion of the consideration paid for the Crude Pipelines and Tankage
Assets acquired from Holly. Union Bank of California, N.A. is one of the lenders and serves as
administrative agent under this agreement. As of December 31, 2008 and December 31, 2007, we had
$200.0 million and zero, respectively, outstanding under the Credit Agreement.
The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital
and for general partnership purposes. Advances under the Credit Agreement that are either
designated for
-54-
working capital or have been used as interim financing to fund capital expenditures are classified
as short-term liabilities. Other advances under the Credit Agreement are classified as long-term
liabilities. In addition, the Credit Agreement is available to fund letters of credit up to a
$50.0 million sub-limit and to fund distributions to unitholders up to a $20.0 million sub-limit.
During the year ended December 31, 2008, we received net advances totaling $29.0 million under the
Credit Agreement that were used as interim financing for capital expenditures.
We may prepay all loans at any time without penalty, except for payment of certain breakage and
related costs. We are required to reduce all working capital borrowings under the Credit Agreement
to zero for a period of at least 15 consecutive days in each twelve-month period prior to the
maturity date of the agreement. As of December 31, 2008, we did not have any working capital
borrowings.
Our obligations under the Credit Agreement are collateralized by substantially all of our assets.
Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P., our general
partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics
Holdings, L.P. would be limited to the extent of their assets, which other than their investment in
HEP, are not significant.
Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference
rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to
1.50%) or (b) at a rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable
margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio
of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes,
depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on
the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the
ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At
December 31, 2008, we are subject to a 0.30% commitment fee on the $100.0 million unused portion of
the Credit Agreement. The agreement expires in August 2011. At that time, the agreement will
terminate and all outstanding amounts thereunder will be due and payable.
The Credit Agreement imposes certain requirements on us, including: a prohibition against
distribution to unitholders if, before or after the distribution, a potential default or an event
of default as defined in the agreement would occur; limitations on our ability to incur debt, make
loans, acquire other companies, change the nature of our business, enter a merger or consolidation,
or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense
ratio and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders
will be able to accelerate the maturity of the debt and exercise other rights and remedies.
Additionally, the Credit Agreement contains certain provisions whereby the lenders may accelerate
payment of outstanding debt under certain circumstances.
Senior Notes Due 2015
Our Senior Notes maturing March 1, 2015 are registered with the SEC and bear interest at 6.25%.
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 Moodys and Standard & Poors 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 their assets, which other than their investment in
HEP, are not significant.
-55-
The carrying amounts of our long-term debt are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Credit Agreement |
|
$ |
200,000 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
Senior Notes |
|
|
|
|
|
|
|
|
Principal |
|
|
185,000 |
|
|
|
185,000 |
|
Unamortized discount |
|
|
(2,344 |
) |
|
|
(2,724 |
) |
Fair value hedge interest rate swap |
|
|
|
|
|
|
(841 |
) |
Unamortized premium dedesignated fair value hedge |
|
|
2,137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
184,793 |
|
|
|
181,435 |
|
|
|
|
|
|
|
|
Total debt |
|
|
384,793 |
|
|
|
181,435 |
|
Less short-term borrowings under credit agreement |
|
|
29,000 |
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
355,793 |
|
|
$ |
181,435 |
|
|
|
|
|
|
|
|
Our interest rate swap contracts are discussed under Risk Management.
The following table presents our long-term contractual obligations as of December 31, 2008.
|
|
Our long-term debt consists of the $185.0 million principal balance of our Senior Notes and
$171.0 millon of outstanding principal under our Credit Agreement that we have classified as
long-term debt. |
|
|
|
The pipeline operating lease amounts below reflect the exercise of the first of three
10-year extensions, expiring in 2017, on our lease agreement for the refined products pipeline
between White Lakes Junction and Kuntz Station in New Mexico. However, these amounts exclude
the second and third 10-year lease extensions, which based on the current outlook, are likely
to be exercised. |
|
|
|
Most of our right of way agreements are renewable on an annual basis, and the right of way
lease payments below include only obligations under the remaining non-cancelable terms of
these agreements at December 31, 2008. For the foreseeable future, we intend to continue
renewing these agreements and expect to incur right of way expenses in addition to the
payments listed below. |
|
|
|
In consideration for Hollys assistance in obtaining our joint venture opportunity in the
SLC Pipeline discussed under Capital Requirements, we will pay Holly a $2.5 million finders
fee upon the closing of our investment in the joint venture with Plains. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
|
|
|
|
|
|
Less than |
|
|
|
|
|
|
|
|
|
|
Over 5 |
|
|
|
Total |
|
|
1 Year |
|
|
2-3 Years |
|
|
4-5 Years |
|
|
Years |
|
|
|
(In thousands) |
|
Long-term debt principal |
|
$ |
356,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
171,000 |
|
|
$ |
185,000 |
|
Long-term debt interest |
|
|
75,157 |
|
|
|
11,563 |
|
|
|
23,125 |
|
|
|
23,125 |
|
|
|
17,344 |
|
Pipeline operating lease |
|
|
52,343 |
|
|
|
6,158 |
|
|
|
12,316 |
|
|
|
12,316 |
|
|
|
21,553 |
|
Right of way leases |
|
|
2,130 |
|
|
|
206 |
|
|
|
393 |
|
|
|
329 |
|
|
|
1,202 |
|
Other |
|
|
23,049 |
|
|
|
5,221 |
|
|
|
5,178 |
|
|
|
4,600 |
|
|
|
8,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
508,679 |
|
|
$ |
23,148 |
|
|
$ |
41,012 |
|
|
$ |
211,370 |
|
|
$ |
233,149 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact of Inflation
Inflation in the United States has been relatively low in recent years and did not have a material
impact on our results of operations for the years ended December 31, 2008, 2007 and 2006.
A substantial majority of our revenues are generated under long-term contracts that include the
right to increase our rates and minimum revenue guarantees annually for increases in the PPI.
Historically, the PPI has increased an average of 4.3% annually over the past 5 calendar years.
With respect to our 15-
-56-
year transportation agreement with Alon, recent data indicates that the annual PPI adjustment may
result in a minor tariff rate decrease.
Environmental Matters
Our operation of pipelines, terminals, and associated facilities in connection with the storage and
transportation of refined products 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. For additional discussion on environmental matter,
please see Environmental Regulation and Remediation under Item 1, Business.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition and results of operations are based upon our
consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States. The preparation of these financial statements
requires us to make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as
of the date of the financial statements. Actual results may differ from these estimates under
different assumptions or conditions. We consider the following policies to be the most critical to
understanding the judgments that are involved and the uncertainties that could impact our results
of operations, financial condition and cash flows.
Revenue Recognition
Revenues are recognized as products are shipped through our pipelines and terminals. Additional
pipeline transportation revenues result from an operating lease by Alon USA, L.P. of an interest in
the capacity of one of our pipelines.
Billings to customers for obligations under their quarterly minimum revenue commitments are
recorded as deferred revenue liabilities if the customer has the right to receive future services
for these billings. The revenue is recognized at the earlier of:
|
|
the customer receives the future services provided by these billings, |
|
|
|
the period in which the customer is contractually allowed to receive the services expires,
or |
|
|
|
we determine a high likelihood that we will not be required to provide services within the
allowed period. |
We will recognize shortfall billings as revenue prior to the expiration of the contractual term
period to provide services only when we determine with a high likelihood that we will not be
required to provide services within the allowed period. We determine this when, based on current
and projected shipping levels, our pipeline systems will not have the necessary capacity to enable
a customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit
within its respective contractual shortfall make-up period or the customer acknowledges that its
anticipated shipment levels will not permit it to utilize such a shortfall credit within the
respective contractual make-up period. To date, we have not recognized any shortfall billings as
revenue prior to the expiration of the contractual term period.
Long-Lived Assets
We calculate depreciation and amortization based on estimated useful lives and salvage values of
our assets. When assets are placed into service, we make estimates with respect to their useful
lives that we believe are reasonable. However, factors such as competition, regulation or
environmental matters could cause us to change our estimates, thus impacting the future calculation
of depreciation and amortization. We evaluate long-lived assets for potential impairment by
identifying whether indicators of impairment exist and, if so, assessing whether the long-lived
assets are recoverable from estimated future undiscounted cash flows. The actual amount of
impairment loss, if any, to be recorded is equal to the amount by which a long-lived assets
carrying value exceeds its fair value. Estimates of future discounted cash flows and fair value of
assets require subjective assumptions with regard to future operating results,
-57-
and actual results could differ from those estimates. No impairments of long-lived assets were
recorded during the years ended December 31, 2008, 2007 and 2006.
Contingencies
It is common in our industry to be subject to proceedings, lawsuits and other claims related to
environmental, labor, product and other matters. We are required to assess the likelihood of any
adverse judgments or outcomes to these types of matters as well as potential ranges of probable
losses. A determination of the amount of reserves required, if any, for these types of
contingencies is made after careful analysis of each individual issue. The required reserves may
change in the future due to developments in each matter or changes in approach such as a change in
settlement strategy in dealing with these potential matters.
Recent Accounting Pronouncements
Statement of Financial Accounting Standard (SFAS) No. 160 Noncontrolling Interests in
Consolidated Financial Statements an Amendment of Accounting Research Bulletin (ARB) No. 51
In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial Statements an Amendment of ARB No. 51. SFAS
No. 160 changes the classification of non-controlling interests, also referred to as minority
interests, in the consolidated financial statements. It also establishes a single method of
accounting for changes in a parent companys ownership interest that do not result in
deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is
deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15,
2008. We will adopt this standard effective January 1, 2009. Upon adoption of this standard, our minority interest balance will be reclassified as a
component of Partners equity in our consolidated balance sheets. At December 31, 2008, our
minority interest balance was $10.2 million.
SFAS No. 161 Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS
No. 133
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging
Activities, an Amendment of SFAS No. 133. This standard amends and expands the disclosure
requirements of SFAS 133 to include disclosure of the objectives and strategies related to an
entitys use of derivative instruments, disclosure of how an entity accounts for its derivative
instruments and disclosure of the financial impact including effect on cash flows associated with
derivative activity. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008
and interim periods within those fiscal years. We will adopt this standard effective January 1,
2009. We do not expect the adoption of this standard to have a material impact on our financial
condition, results of operations and cash flows.
EITF No. 07-04 Application of the Two-Class Method under FASB Statement No. 128, Earnings per
Share, to Master Limited Partnerships
In March 2008, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 07-04, Application
of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (MLPs).
This standard provides guidance in the application of the two-class method in computing earnings
per unit to reflect an MLPs contractual obligation to make distributions to the general partner,
limited partners, and incentive distribution rights holder. EITF No. 07-04 is effective for fiscal
years beginning after December 15, 2008, and interim periods within those fiscal years. We will
adopt this standard effective January 1, 2009. We do not expect the adoption of this standard to
have a material impact on our financial condition, results of operations and cash flows.
FASB Staff Position (FSP) No. EITF 03-6-1 Determining Whether Instruments Granted in Share-Based
Transactions Are Participating Securities
In June 2006, the FASB issued FSP No. 03-6-1, Determining Whether Instruments Granted in
Share-Based Transactions Are Participating Securities. This standard provides guidance in
determining whether unvested instruments granted under share-based payment transactions are
participating securities and, therefore, should be included in earnings per share calculations
under the two-class
method provided under FASB No. 128, Earnings per Share. FSP No. 03-6-1 is effective for fiscal
years
-58-
beginning after December 15, 2008, and interim periods within those fiscal years. We will adopt
this standard effective January 1, 2009. We do not expect the adoption of this standard to have a
material impact on our financial condition, results of operations and cash flows.
RISK MANAGEMENT
As of December 31, 2008, we have three interest rate swap contracts.
We entered into an interest rate swap to hedge our exposure to the cash flow risk caused by the
effects of LIBOR changes on the $171.0 million Credit Agreement advance that we used to finance our
purchase of the Crude Pipelines and Tankage Assets from Holly. This interest rate swap effectively
converts our $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74%
plus an applicable margin, currently 1.75%, which equaled an effective interest rate of 5.49% as of
December 31, 2008. The maturity date of this swap contract is February 28, 2013. We intend to
renew our Credit Agreement prior to its expiration in August 2011 and continue to finance the
$171.0 million balance until the swap matures.
We have designated this interest rate swap as a cash flow hedge. Based on our assessment of
effectiveness using the change in variable cash flows method, we have determined that this interest
rate swap is effective in offsetting the variability in interest payments on our $171.0 million
variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash
flow hedge to its fair value on a quarterly basis with a corresponding offset to accumulated other
comprehensive income. Also on a quarterly basis, we measure hedge effectiveness by comparing the
present value of the cumulative change in the expected future interest to be paid or received on
the variable leg of our swap against the expected future interest payments on our $171.0 million
variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive
income to interest expense. As of December 31, 2008, we had no ineffectiveness on our cash flow
hedge.
We also have an interest rate swap contract that effectively converts interest expense associated
with $60.0 million of our 6.25% Senior Notes from fixed to variable rate debt (Variable Rate
Swap). Under this swap contract, interest on the $60.0 million notional amount is computed using
the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 3.36%
as of December 31, 2008. The maturity date of this swap contract is March 1, 2015, matching the
maturity of the Senior Notes.
In October 2008, we entered into an additional interest rate swap contract, effective December 1,
2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting
$60.0 million of our hedged long-term debt back to fixed rate debt (Fixed Rate Swap). Under the
Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of
3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap
results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is
December 1, 2013.
Our interest rate swaps not having a hedge designation are measured quarterly at fair value
either as an asset or a liability in our consolidated balance sheets with a corresponding entry to
interest expense. For the year ended December 31, 2008, we recognized $2.3 million in interest
expense attributable to fair value adjustments to our interest rate swaps.
Prior to the execution of our Fixed Rate Swap, the Variable Rate Swap was designated as a fair
value hedge of $60.0 million in outstanding principal under the Senior Notes. This hedge met the
requirements to assume no ineffectiveness and was accounted for using the shortcut method of
accounting whereby offsetting fair value adjustments to the underlying swap were made to the
carrying value of the Senior Notes, effectively adjusting the carrying value this $60.0 million to
its fair value. We dedesignated this hedge in October 2008. At this time, the carrying balance of
our Senior Notes included a $2.2 million premium due to the application of hedge accounting until
the dedesignation date. This premium is being amortized as a reduction to interest expense over
the remaining term of the Variable Rate Swap.
-59-
We record interest expense equal to the variable rate payments under the swaps. Receipts under the
swap agreements are recorded as a reduction of interest expense.
Additional information on our interest rate swaps is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
|
|
|
Location of |
|
|
|
Interest Rate Swaps |
|
Location |
|
Fair Value |
|
|
Offsetting Balance |
|
Offsetting Amount |
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
Asset |
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-variable
interest rate swap
$60 million of
6.25% Senior Notes
|
|
Other assets
|
|
$ |
4,079 |
|
|
Long-term debt
|
|
$ |
(2,195
|
) |
|
|
|
|
|
|
|
|
Interest expense
|
|
$ |
(1,884 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,079 |
|
|
|
|
$ |
(4,079 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability |
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedge
$171 million LIBOR
based debt
|
|
Other long-term
liabilities
|
|
$ |
(12,967 |
) |
|
Accumulated other
comprehensive income
|
|
$ |
12,967 |
|
Variable-to-fixed
interest rate swap
$60 million
|
|
Other long-term
liabilities
|
|
|
(4,166 |
) |
|
Interest expense
|
|
|
4,166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(17,133 |
) |
|
|
|
$ |
17,133 |
|
|
|
|
|
|
|
|
|
|
|
|
The market risk inherent in our fixed-rate debt and positions is the potential change arising from
increases or decreases in interest rates as discussed below.
At December 31, 2008, we had an outstanding principal balance on our 6.25% Senior Notes of $185.0
million. By means of our interest rate swap contracts, we have effectively converted the 6.25%
fixed rate on $60.0 million of the Senior Notes to a fixed rate of 4.75%. A change in interest
rates would generally affect the fair value of the debt, but not our earnings or cash flows. At
December 31, 2008, the fair value of our Senior Notes was $124.0 million. We estimate a
hypothetical 10% change in the yield-to-maturity applicable to the Senior Notes at December 31,
2008 would result in a change of approximately $7.8 million in the fair value of the debt.
At December 31, 2008, 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 formed 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.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. See Risk
Management under Managements 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.
-60-
Item 8. Financial Statements and Supplementary Data
MANAGEMENTS REPORT ON ITS ASSESSMENT OF THE COMPANYS INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Holly Energy Partners, L.P. (the Partnership) is responsible for establishing and
maintaining adequate internal control over financial reporting.
All internal control systems, no matter how well designed, have inherent limitations. Therefore,
even those systems determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation.
Management assessed the Partnerships internal control over financial reporting as of December 31,
2008 using the criteria for effective control over financial reporting established in Internal
Control Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on this assessment, management believes that, as of December 31, 2008,
the Partnership maintained effective internal control over financial reporting.
The Partnerships independent registered public accounting firm has issued an attestation report on
the effectiveness of the Partnerships internal control over financial reporting as of December 31,
2008. That report appears on page 62.
-61-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Holly Logistic Services, L.L.C. and
Unitholders of Holly Energy Partners, L.P.
We have audited Holly Energy Partners, L.P.s (the Partnership) internal control over financial
reporting as of December 31 2008, based on criteria established in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO
criteria). The Partnerships management is responsible for maintaining effective internal control
over financial reporting, and for its assessment of the effectiveness of internal control over
financial reporting included in the accompanying managements report. Our responsibility is to
express an opinion on the effectiveness of the partnerships internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Holly Energy Partners, L.P. maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Holly Energy Partners, L.P. as of
December 31, 2008 and 2007, and the related consolidated statements of income, partners equity
(deficit), and cash flows for each of the three years in the period ended December 31, 2008, our
report dated February 13, 2009, expressed an unqualified opinion thereon.
Dallas, Texas
February 13, 2009
-62-
Index to Consolidated Financial Statements
|
|
|
|
|
Page |
|
|
Reference |
|
|
|
|
|
64 |
|
|
|
|
|
65 |
|
|
|
|
|
66 |
|
|
|
|
|
67 |
|
|
|
|
|
68 |
|
|
|
|
|
69 |
-63-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Holly Logistic Services, L.L.C. and
Unitholders of Holly Energy Partners, L.P.
We have audited the accompanying consolidated balance sheets of Holly Energy Partners, L.P. (the
Partnership) as of December 31, 2008 and 2007, and the related consolidated statements of income,
partners equity (deficit), and cash flows for each of the three years in the period ended December
31, 2008. These financial statements are the responsibility of the Partnerships management. Our
responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and significant estimates made
by management, and evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Holly Energy Partners, L.P. at December
31, 2008 and 2007, and the related consolidated results of its operations and its cash flows, for
each of the three years in the period ended December 31, 2008 in conformity with U.S. generally
accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), Holly Energy Partners, L.P.s internal control over financial reporting as
of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
February 13, 2009 expressed an unqualified opinion thereon.
Dallas, Texas
February 13, 2009
-64-
Holly Energy Partners, L.P.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands, except unit data) |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
5,269 |
|
|
$ |
10,321 |
|
Accounts receivable: |
|
|
|
|
|
|
|
|
Trade |
|
|
5,082 |
|
|
|
6,611 |
|
Affiliates |
|
|
9,395 |
|
|
|
5,700 |
|
|
|
|
|
|
|
|
|
|
|
14,477 |
|
|
|
12,311 |
|
|
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
593 |
|
|
|
546 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
20,339 |
|
|
|
23,178 |
|
|
|
|
|
|
|
|
|
|
Properties and equipment, net |
|
|
290,284 |
|
|
|
158,600 |
|
Transportation agreements, net |
|
|
122,383 |
|
|
|
54,273 |
|
Other assets |
|
|
6,682 |
|
|
|
2,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
439,688 |
|
|
$ |
238,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY (DEFICIT) |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
5,816 |
|
|
$ |
3,011 |
|
Accounts payable affiliates |
|
|
2,202 |
|
|
|
6,021 |
|
Accrued interest |
|
|
2,845 |
|
|
|
2,996 |
|
Deferred revenue |
|
|
15,658 |
|
|
|
3,700 |
|
Accrued property taxes |
|
|
1,145 |
|
|
|
1,177 |
|
Other current liabilities |
|
|
1,505 |
|
|
|
827 |
|
Short-term borrowings under credit agreement |
|
|
29,000 |
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
58,171 |
|
|
|
17,732 |
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
355,793 |
|
|
|
181,435 |
|
Other long-term liabilities |
|
|
17,604 |
|
|
|
1,181 |
|
Minority interest |
|
|
10,218 |
|
|
|
10,740 |
|
|
|
|
|
|
|
|
|
|
Partners equity (deficit): |
|
|
|
|
|
|
|
|
Common unitholders (8,390,000 and 8,170,000 units
issued and outstanding at December 31, 2008 and
2007, respectively) |
|
|
169,126 |
|
|
|
172,807 |
|
Subordinated unitholders (7,000,000 units issued
and outstanding at December 31, 2008 and 2007) |
|
|
(85,059 |
) |
|
|
(73,725 |
) |
Class B subordinated unitholders (937,500 units
issued and outstanding at December 31, 2008 and
2007) |
|
|
21,455 |
|
|
|
22,973 |
|
General partner interest (2% interest) |
|
|
(94,653 |
) |
|
|
(94,239 |
) |
Accumulated other comprehensive loss |
|
|
(12,967 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners equity (deficit) |
|
|
(2,098 |
) |
|
|
27,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity (deficit) |
|
$ |
439,688 |
|
|
$ |
238,904 |
|
|
|
|
|
|
|
|
See accompanying notes.
-65-
Holly Energy Partners, L.P.
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands, except per unit data) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
85,040 |
|
|
$ |
63,709 |
|
|
$ |
52,878 |
|
Third parties |
|
|
33,048 |
|
|
|
41,698 |
|
|
|
36,316 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
118,088 |
|
|
|
105,407 |
|
|
|
89,194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
41,270 |
|
|
|
32,911 |
|
|
|
28,630 |
|
Depreciation and amortization |
|
|
22,889 |
|
|
|
14,382 |
|
|
|
15,330 |
|
General and administrative |
|
|
6,377 |
|
|
|
5,043 |
|
|
|
4,854 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70,536 |
|
|
|
52,336 |
|
|
|
48,814 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
47,552 |
|
|
|
53,071 |
|
|
|
40,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
159 |
|
|
|
533 |
|
|
|
899 |
|
Interest expense |
|
|
(21,763 |
) |
|
|
(13,289 |
) |
|
|
(13,056 |
) |
Gain on sale of assets |
|
|
36 |
|
|
|
298 |
|
|
|
|
|
Other Income |
|
|
996 |
|
|
|
|
|
|
|
|
|
Minority interest in Rio Grande Pipeline Company |
|
|
(1,278 |
) |
|
|
(1,067 |
) |
|
|
(680 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,850 |
) |
|
|
(13,525 |
) |
|
|
(12,837 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
25,702 |
|
|
|
39,546 |
|
|
|
27,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
(335 |
) |
|
|
(275 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
25,367 |
|
|
|
39,271 |
|
|
|
27,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less general partner interest in net income |
|
|
3,543 |
|
|
|
2,932 |
|
|
|
1,710 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
21,824 |
|
|
$ |
36,339 |
|
|
$ |
25,833 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partners unit
basic and diluted |
|
$ |
1.34 |
|
|
$ |
2.26 |
|
|
$ |
1.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partners units outstanding |
|
|
16,291 |
|
|
|
16,108 |
|
|
|
16,108 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
-66-
Holly Energy Partners, L.P.
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands) |
|
Cash flows from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
25,367 |
|
|
$ |
39,271 |
|
|
$ |
27,543 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
22,889 |
|
|
|
14,382 |
|
|
|
15,330 |
|
Change in fair value interest rate swaps |
|
|
2,282 |
|
|
|
|
|
|
|
|
|
Minority interest in Rio Grande Pipeline Company |
|
|
1,278 |
|
|
|
1,067 |
|
|
|
680 |
|
Amortization of restricted and performance units |
|
|
1,688 |
|
|
|
1,375 |
|
|
|
927 |
|
Gain on sale of assets |
|
|
(36 |
) |
|
|
(298 |
) |
|
|
|
|
(Increase) decrease in current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
1,529 |
|
|
|
728 |
|
|
|
(4,263 |
) |
Accounts receivable affiliates |
|
|
(3,695 |
) |
|
|
16 |
|
|
|
(637 |
) |
Prepaid and other current assets |
|
|
(47 |
) |
|
|
666 |
|
|
|
115 |
|
Increase (decrease) in current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
|
2,805 |
|
|
|
(770 |
) |
|
|
761 |
|
Accounts payable affiliates |
|
|
(3,819 |
) |
|
|
3,823 |
|
|
|
764 |
|
Accrued interest |
|
|
(151 |
) |
|
|
55 |
|
|
|
49 |
|
Deferred revenue |
|
|
11,958 |
|
|
|
(1,786 |
) |
|
|
4,473 |
|
Accrued property taxes |
|
|
(32 |
) |
|
|
309 |
|
|
|
(144 |
) |
Other current liabilities |
|
|
678 |
|
|
|
(271 |
) |
|
|
(215 |
) |
Other, net |
|
|
957 |
|
|
|
489 |
|
|
|
470 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
63,651 |
|
|
|
59,056 |
|
|
|
45,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to properties and equipment |
|
|
(42,303 |
) |
|
|
(9,957 |
) |
|
|
(9,107 |
) |
Acquisition of crude pipelines and tankage assets |
|
|
(171,000 |
) |
|
|
|
|
|
|
|
|
Proceeds from sale of assets |
|
|
36 |
|
|
|
325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used for investing activities |
|
|
(213,267 |
) |
|
|
(9,632 |
) |
|
|
(9,107 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net borrowings under credit agreement |
|
|
200,000 |
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common units |
|
|
104 |
|
|
|
|
|
|
|
|
|
Contribution from general partner |
|
|
186 |
|
|
|
|
|
|
|
|
|
Distributions to partners |
|
|
(52,426 |
) |
|
|
(47,974 |
) |
|
|
(43,670 |
) |
Distributions to minority interest |
|
|
(1,800 |
) |
|
|
(1,290 |
) |
|
|
(1,470 |
) |
Purchase of units for restricted grants |
|
|
(795 |
) |
|
|
(1,082 |
) |
|
|
(634 |
) |
Deferred financing costs |
|
|
(705 |
) |
|
|
(296 |
) |
|
|
|
|
Other |
|
|
|
|
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used for) financing activities |
|
|
144,564 |
|
|
|
(50,658 |
) |
|
|
(45,774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
Decrease for the year |
|
|
(5,052 |
) |
|
|
(1,234 |
) |
|
|
(9,028 |
) |
Beginning of year |
|
|
10,321 |
|
|
|
11,555 |
|
|
|
20,583 |
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
5,269 |
|
|
$ |
10,321 |
|
|
$ |
11,555 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
-67-
Holly Energy Partners, L.P.
Consolidated Statements of Partners Equity (Deficit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Class B |
|
|
General |
|
|
Other |
|
|
|
|
|
|
Common |
|
|
Subordinated |
|
|
Subordinated |
|
|
Partner |
|
|
Comprehensive |
|
|
|
|
|
|
Units |
|
|
Units |
|
|
Units |
|
|
Interest |
|
|
Loss |
|
|
Total |
|
|
|
(In thousands) |
|
|
Balance December 31, 2005 |
|
$ |
184,568 |
|
|
$ |
(63,153 |
) |
|
$ |
24,388 |
|
|
$ |
(93,743 |
) |
|
$ |
|
|
|
$ |
52,060 |
|
|
Distributions to partners |
|
|
(21,120 |
) |
|
|
(18,095 |
) |
|
|
(2,423 |
) |
|
|
(2,032 |
) |
|
|
|
|
|
|
(43,670 |
) |
Purchase of units for restricted
grants |
|
|
(634 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(634 |
) |
Amortization of restricted units |
|
|
927 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
927 |
|
Net income |
|
|
13,103 |
|
|
|
11,226 |
|
|
|
1,504 |
|
|
|
1,710 |
|
|
|
|
|
|
|
27,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2006 |
|
|
176,844 |
|
|
|
(70,022 |
) |
|
|
23,469 |
|
|
|
(94,065 |
) |
|
|
|
|
|
|
36,226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to partners |
|
|
(22,762 |
) |
|
|
(19,495 |
) |
|
|
(2,611 |
) |
|
|
(3,106 |
) |
|
|
|
|
|
|
(47,974 |
) |
Purchase of units for
restricted grants |
|
|
(1,082 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,082 |
) |
Amortization of restricted and
performance units |
|
|
1,375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,375 |
|
Net income |
|
|
18,432 |
|
|
|
15,792 |
|
|
|
2,115 |
|
|
|
2,932 |
|
|
|
|
|
|
|
39,271 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007 |
|
|
172,807 |
|
|
|
(73,725 |
) |
|
|
22,973 |
|
|
|
(94,239 |
) |
|
|
|
|
|
|
27,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to partners |
|
|
(24,788 |
) |
|
|
(20,720 |
) |
|
|
(2,775 |
) |
|
|
(4,143 |
) |
|
|
|
|
|
|
(52,426 |
) |
Purchase of units for
restricted grants |
|
|
(795 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(795 |
) |
Amortization of restricted and
performance units |
|
|
1,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,688 |
|
Issuance of common units |
|
|
9,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,104 |
|
Cost of issuing common units |
|
|
(71 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(71 |
) |
Capital contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
186 |
|
|
|
|
|
|
|
186 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
11,181 |
|
|
|
9,386 |
|
|
|
1,257 |
|
|
|
3,543 |
|
|
|
|
|
|
|
25,367 |
|
Change in fair value cash
flow hedge |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,967 |
) |
|
|
(12,967 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
11,181 |
|
|
|
9,386 |
|
|
|
1,257 |
|
|
|
3,543 |
|
|
|
(12,967 |
) |
|
|
12,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008 |
|
$ |
169,126 |
|
|
$ |
(85,059 |
) |
|
$ |
21,455 |
|
|
$ |
(94,653 |
) |
|
$ |
(12,967 |
) |
|
$ |
(2,098 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
-68-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2008
Note 1: Description of Business and Summary of Significant Accounting Policies
Description of Business
Holly Energy Partners, L.P. (HEP) together with its consolidated subsidiaries, is a publicly held
master limited partnership, currently 46% owned by Holly Corporation (Holly). We commenced
operations on July 13, 2004 upon the completion of our initial public offering. In these
consolidated financial statements, the words we, our, ours and us refer to HEP unless the
context otherwise indicates.
We operate in one business segment the operation of petroleum product and crude oil pipelines,
tankage and terminal facilities.
One of Hollys wholly-owned subsidiaries owns a refinery in Artesia, New Mexico, which Holly
operates in conjunction with crude, vacuum distillation and other facilities situated in Lovington,
New Mexico (collectively, the Navajo Refinery). The Navajo Refinery produces high-value refined
products such as gasoline, diesel fuel and jet fuel and serves markets in the southwestern United
States and northern Mexico. We own and operate the two parallel intermediate feedstock pipelines
(the Intermediate Pipelines), which connect the New Mexico refining facilities. Our operations
serving the Navajo Refinery include refined product pipelines that serve as part of the refinerys
product distribution network. We also own and operate crude oil pipelines and on-site crude oil
tankage that supply and support the refinery. Our terminal operations serving the Hollys Navajo
Refinery include a truck rack at the Navajo Refinery and five integrated refined product terminals
located in New Mexico, Texas and Arizona.
Another of Hollys wholly-owned subsidiaries owns a refinery located near Salt Lake City, Utah (the
Woods Cross Refinery). Our operations serving the Woods Cross Refinery include crude oil and
refined product pipelines, crude oil tankage and a truck rack at the refinery, a refined product
terminal in Spokane, Washington and a 50% non-operating interest in product terminals in Boise and
Burley, Idaho.
See Note 2 for information on the crude pipelines and tankage assets acquired from Holly on
February 29, 2008 (the Crude Pipelines and Tankage Assets).
We also own and operate refined products pipelines and terminals, located primarily in Texas, that
service Alon USA, Inc.s (Alon) refinery in Big Spring, Texas.
Additionally, we own a refined product terminal in Mountain Home, Idaho, and a 70% interest in Rio
Grande Pipeline Company (Rio Grande), which provides transportation of liquid petroleum gases to
northern Mexico.
Principles of Consolidation
The consolidated financial statements include our accounts and those of our subsidiaries and Rio
Grande. All significant inter-company transactions and balances have been eliminated. The
pipeline and terminal assets that were contributed to us from Holly concurrently with the
completion of our initial public offering in 2004, as well as the intermediate pipeline assets that
were purchased from Holly in July 2005 were accounted for as transactions among entities under
common control. Accordingly, these assets were recorded on our balance sheets at Hollys book
basis instead of our purchase price or fair value.
If the assets transferred to us upon our initial public offering in 2004 and the intermediate
pipelines purchased from Holly in 2005 had been acquired from third parties, our acquisition cost
in excess of Hollys basis in the transferred assets of $157.3 million would have been recorded as
increases to our properties and equipment and intangible assets instead of reductions to our
partners equity.
-69-
Use of Estimates
The preparation of financial statements in accordance with U.S. generally accepted accounting
principles (GAAP) requires management to make estimates and assumptions that affect the amounts
reported in the financial statements and accompanying notes. Actual results could differ from
those estimates.
Cash and Cash Equivalents
For purposes of the statements of cash flows, we consider all highly liquid investments with
maturity of three months or less at the time of purchase to be cash equivalents. The carrying
amounts reported on the balance sheet approximate fair value due to the short-term maturity of
these instruments.
Accounts Receivable
The majority of the accounts receivable are due from affiliates of Holly, Alon or independent
companies in the petroleum industry. Credit is extended based on evaluation of the customers
financial condition and, in certain circumstances, collateral such as letters of credit or
guarantees, may be required. Credit losses are charged to income when accounts are deemed
uncollectible and historically have been minimal.
Inventories
Inventories consisting of materials and supplies used for operations are stated at the lower of
cost, using the average cost method, or market and are shown under Prepaid and other current
assets in our consolidated balance sheets.
Properties and Equipment
Properties and equipment are stated at cost. Depreciation is provided by the straight-line method
over the estimated useful lives of the assets; primarily 10 to 16 years for terminal facilities, 23
to 33 years for pipelines and 3 to 10 years for corporate and other assets. Maintenance, repairs
and major replacements are generally expensed as incurred. Costs of replacements constituting
improvement are capitalized.
Transportation Agreements
The transportation agreement assets are stated at cost and are being amortized over the periods of
the agreements using the straight-line method.
Long-Lived Assets
We evaluate long-lived assets, including intangible assets, for potential impairment by identifying
whether indicators of impairment exist and, if so, assessing whether the long-lived assets are
recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss,
if any, to be recorded is equal to the amount by which a long-lived assets carrying value exceeds
its fair value. No impairments of long-lived assets were recorded during the periods included in
these financial statements.
Asset Retirement Obligations
We record legal obligations associated with the retirement of long-lived assets that result from
the acquisition, construction, development and/or the normal operation of our long-lived assets.
The fair value of the estimated cost to retire a tangible long-lived asset is recorded in the
period in which the liability is incurred and when a reasonable estimate of the fair value of the
liability can be made. If a reasonable estimate cannot be made at the time the liability is
incurred, we record the liability when sufficient information is available to estimate the
liabilitys fair value.
We have asset retirement obligations with respect to certain of our assets due to legal obligations
to clean and/or dispose of various component parts at the time they are retired. At December 31,
2008, an asset retirement obligation of $0.4 million is included in Other long-term liabilities
in our consolidated balance sheets.
-70-
Fair Value Measurements
We adopted Statement of Financial Accounting Standards (SFAS) No. 157 Fair Value Measurements
on January 1, 2008 for financial instruments that we recognize at fair value on a recurring basis.
This standard defines fair value, establishes a framework for measuring fair value and prescribes
expanded disclosures about fair value measurements. It also establishes a fair value hierarchy
that categorizes inputs used in fair value measurements into three broad levels. Under this
hierarchy, quoted prices in active markets for identical assets or liabilities are considered the
most reliable evidence of fair value and are given the highest priority level (level 1). Quoted
market prices for similar assets and liabilities in an active market, quoted prices for identical
assets or liabilities in an inactive market and calculation techniques utilizing observable market
inputs are given a lower priority level (Level 2). Unobservable inputs are considered the least
reliable and are given the lowest priority level (level 3).
We have interest rate swaps that we measure at fair value on a recurring basis using level 2
inputs. Our interest rate swap fair value measurements are based on the net present value of
expected future cash flows related to both variable and fixed rate legs of our interest rate swap
agreements. Our measurements are computed using the forward LIBOR yield curve, a market-based
observable input, at our respective measurement dates. See Note 6 for additional information on
our interest rate swaps.
Revenue Recognition
Revenues are recognized as products are shipped through our pipelines and terminals. Billings to
customers for obligations under their quarterly minimum revenue commitments are recorded as
deferred revenue liabilities if the customer has the right to receive future services for these
billings. The revenue is recognized at the earlier of:
|
|
the customer receives the future services provided by these billings, |
|
|
|
the period in which the customer is contractually allowed to receive the services expires,
or |
|
|
|
we determine a high likelihood that we will not be required to provide services within the
allowed period. |
We recognize shortfall billings as revenue prior to the expiration of the contractual term period
to provide services only when we determine with a high likelihood that we will not be required to
provide services within the allowed period. We determine this when based on current and projected
shipping levels, that our pipeline systems will not have the necessary capacity to enable a
customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit
within its respective contractual shortfall make up period or the customer acknowledges that its
anticipated shipment levels will not permit it to utilize such a shortfall credit within the
respective contractual make up period. To date, we have not recognized any shortfall billings as
revenue prior to the expiration of the contractual term period.
Additional pipeline transportation revenues result from an operating lease to a third party of an
interest in the capacity of one of our pipelines.
Taxes billed and collected from our pipeline and terminal customers are recorded on a net basis
with no effect on net income.
Environmental Costs
Environmental costs are expensed if they relate to an existing condition caused by past operations
and do not contribute to current or future revenue generation. Liabilities are recorded when site
restoration and environmental remediation, cleanup and other obligations are either known or
considered probable and can be reasonably estimated. Environmental costs recoverable through
insurance, indemnification arrangements or other sources are included in other assets to the extent
such recoveries are considered probable. At December 31, 2008, we had an accrual of $0.2 million
related to environmental remediation obligations.
-71-
State Income Tax
Effective January 1, 2007, the Texas margin tax applied to legal entities conducting business in
Texas, including previously non-taxable entities such as limited partnerships and limited liability
partnerships. The margin tax is based on our Texas sourced taxable margin. The tax is calculated
by applying a tax rate to a base that considers both revenues and expenses and therefore has the
characteristics of an income tax.
We are organized as a pass-through for federal income tax purposes. As a result, our partners are
responsible for federal income taxes based on their respective share of taxable income.
Net income for financial statement purposes may differ significantly from taxable income reportable
to unitholders as a result of differences between the tax bases and financial reporting bases of
assets and liabilities and the taxable income allocation requirements under the partnership
agreement. Individual unitholders have different investment bases depending upon the timing and
price of acquisition of their partnership units. Furthermore, each unitholders tax accounting,
which is partially dependent upon the unitholders tax position, differs from the accounting
followed in the consolidated financial statements. Accordingly, the aggregate difference in the
basis of our net assets for financial and tax reporting purposes cannot be readily determined
because information regarding each unitholders tax attributes in our partnership is not available
to us.
Net Income per Limited Partners Unit
We have identified the general partner interest and the subordinated units as participating
securities and use the two-class method when calculating the net income per unit applicable to
limited partners, which is based on the weighted-average number of common and subordinated units
outstanding during the year. Net income per unit applicable to limited partners (including
subordinated units and Class B subordinated units) is computed by dividing limited partners
interest in net income, after deducting the general partners 2% interest and incentive
distributions, by the weighted-average number of outstanding common and subordinated units.
Recent Accounting Pronouncements
SFAS No. 160 Noncontrolling Interests in Consolidated Financial Statements an Amendment of
Accounting Research Bulletin (ARB) No. 51
In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial Statements an Amendment of ARB No. 51. SFAS
No. 160 changes the classification of non-controlling interests, also referred to as minority
interests, in the consolidated financial statements. It also establishes a single method of
accounting for changes in a parent companys ownership interest that do not result in
deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is
deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15,
2008. We will adopt this standard effective January 1, 2009. Upon adoption of this standard, our minority interest balance will be reclassified as a
component of Partners equity in our consolidated balance sheets. At December 31, 2008, our
minority interest balance was $10.2 million.
SFAS No. 161 Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS
No. 133
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging
Activities, an Amendment of SFAS No. 133. This standard amends and expands the disclosure
requirements of SFAS 133 to include disclosure of the objectives and strategies related to an
entitys use of derivative instruments, disclosure of how an entity accounts for its derivative
instruments and disclosure of the financial impact including effect on cash flows associated with
derivative activity. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008
and interim periods with in those fiscal years. We will adopt this standard effective January 1,
2009. We do not expect the adoption of this standard to have a material impact on our financial
condition, results of operations and cash flows.
-72-
EITF No. 07-04 Application of the Two-Class Method under FASB Statement No. 128, Earnings per
Share, to Master Limited Partnerships
In March 2008, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 07-04, Application
of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (MLPs).
This standard provides guidance in the application of the two-class method in computing earnings
per unit to reflect an MLPs contractual obligation to make distributions to the general partner,
limited partners, and incentive distribution rights holder. EITF No. 07-04 is effective for fiscal
years beginning after December 15, 2008 and interim periods within those fiscal years. We will
adopt this standard effective January 1, 2009. We do not expect the adoption of this standard to
have a material impact on our financial condition, results of operations and cash flows.
FASB Staff Position (FSP) No. EITF 03-6-1 Determining Whether Instruments Granted in Share-Based
Transactions Are Participating Securities
In June 2006, the FASB issued FSP No. 03-6-1, Determining Whether Instruments Granted in
Share-Based Transactions Are Participating Securities. This standard provides guidance in
determining whether unvested instruments granted under share-based payment transactions are
participating securities and, therefore, should be included in earnings per share calculations
under the two-class method provided under SFAS No. 128, Earnings per Share. FSP No. 03-6-1 is
effective for fiscal years beginning after December 15, 2008, and interim periods within those
fiscal years. We will adopt this standard effective January 1, 2009. We do not expect the
adoption of this standard to have a material impact on our financial condition, results of
operations and cash flows.
Note 2: Holly Crude Pipelines and Tankage Transaction
On February 29, 2008, we acquired the Crude Pipelines and Tankage Assets from Holly for $180.0
million that consist of crude oil trunk lines that deliver crude oil to Hollys Navajo Refinery in
southeast New Mexico, gathering and connection pipelines located in west Texas and New Mexico,
on-site crude tankage located within the Navajo and Woods Cross refinery complexes, a jet fuel
products pipeline between Artesia and Roswell, New Mexico, a leased jet fuel terminal in Roswell,
New Mexico and crude oil and product pipelines that support Hollys Woods Cross Refinery. The
consideration paid consisted of $171.0 million in cash and 217,497 of our common units having a
fair value of $9.0 million. We financed the $171.0 million cash portion of the consideration
through borrowings under our senior secured revolving credit agreement expiring August 2011.
In connection with this transaction, we entered into a 15-year crude pipelines and tankage
agreement with Holly. Under the Holly CPTA, Holly agreed to transport and store volumes of crude
oil on the crude pipelines and tankage facilities that at the agreed rates will result in minimum
annual payments to us of $26.8 million. These minimum annual payments or revenue will be adjusted
each year at a rate equal to the percentage change in the Producer Price Index (PPI) but will not
decrease as a result of a decrease in the PPI. Under the agreement, the tariff rates will
generally be increased annually by the percentage change in the Federal Energy Regulatory
Commission (FERC) Oil Pipeline Index. The FERC index is the change in the PPI plus a FERC
adjustment factor which is reviewed periodically. Additionally, Holly amended our omnibus
agreement (the Omnibus Agreement) to provide $7.5 million of indemnification for a period of up
to fifteen years for environmental noncompliance and remediation liabilities associated with the
Crude Pipelines and Tankage Assets that occurred or existed prior to our acquisition.
The $180.0 million purchase price and $0.3 million of related transaction costs was allocated to
the underlying Crude Pipelines and Tankage Assets based on values derived under both market and
cost valuation approaches. Under the market approach, certain values were obtained based on an
analysis of sales data for similar assets in the market, adjusted for certain factors. Under the
cost approach, the replacement cost of certain assets, adjusted for factors including age and
physical wear, served as the basis for value. As a result, we recorded property and equipment of
$106.1 million. Additionally we recorded an intangible asset of $74.2 million representing the
value of the Holly CPTA. This value was derived under an income approach based on the agreements
expected contribution to our future earnings. This intangible asset is included in Transportation
agreements, net in our consolidated balance sheets.
-73-
Note 3: Properties and Equipment
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
Pipelines and terminals |
|
$ |
308,056 |
|
|
$ |
196,800 |
|
Land and right of way |
|
|
24,991 |
|
|
|
22,825 |
|
Other |
|
|
11,498 |
|
|
|
5,706 |
|
Construction in progress |
|
|
38,589 |
|
|
|
9,103 |
|
|
|
|
|
|
|
|
|
|
|
383,134 |
|
|
|
234,434 |
|
Less accumulated depreciation |
|
|
92,850 |
|
|
|
75,834 |
|
|
|
|
|
|
|
|
|
|
$ |
290,284 |
|
|
$ |
158,600 |
|
|
|
|
|
|
|
|
During the year ended December 31, 2008 we capitalized $1.0 million in interest related to major
construction projects. We did not capitalize any interest prior to 2008.
Depreciation expense was $16.7 million, $11.8 million and $11.2 million for the years ended
December 31, 2008, 2007 and 2006, respectively.
Note 4: Transportation Agreements
Our transportation agreements consist of the following:
|
|
The Alon transportation agreement represents a portion of the total purchase price of the
Alon assets that was allocated based on an estimated fair value derived under an income
approach. This asset is being amortized over 30 years ending 2035, the 15-year initial term
of the Alon PTA plus the expected 15-year extension period. |
|
|
|
The Holly crude pipelines and tankage agreement represents a portion of the total purchase
price of the Crude Pipelines and Tankage Assets that was allocated using a fair value based on
the agreements expected contribution to our future earnings under an income approach. This
asset is being amortized over 15 years ending 2023, the 15-year term of the Holly CPTA. |
The carrying amounts of the transportation agreements are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
Alon transportation agreement |
|
$ |
59,933 |
|
|
$ |
59,933 |
|
Holly crude pipelines and tankage
agreement |
|
|
74,231 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
134,164 |
|
|
|
59,933 |
|
Less accumulated amortization |
|
|
11,781 |
|
|
|
5,660 |
|
|
|
|
|
|
|
|
|
|
$ |
122,383 |
|
|
$ |
54,273 |
|
|
|
|
|
|
|
|
We have two additional 15-year transportation agreements with Holly. One of the agreements relates
to the pipelines and terminals contributed to us from Holly at the time of our initial public
offering in 2004 (the Holly PTA). The second agreement relates to the Intermediate Pipelines
acquired from Holly in 2005 (the Holly IPA). Our basis in the assets acquired under these
transfers reflect Hollys historical cost and do not reflect a step-up in basis to fair value.
Therefore, these agreements have a recorded value of zero.
-74-
Note 5: Employees, Retirement and Benefit Plans
Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C.
(HLS), a Holly subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits and
other direct costs are charged to us monthly in accordance with the Omnibus Agreement.
These employees participate in the retirement and benefit plans of Holly. Our share of retirement
and benefit plan costs for the years ended December 31, 2008, 2007 and 2006 was $2.1 million, $1.3
million and $1.4 million, respectively. These amounts include retirement costs of $1.1 million,
$0.6 million and $0.5 million for the years ended December 31, 2008, 2007 and 2006, 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.
On December 31, 2008, we had two types of equity-based compensation, which are described below.
The compensation cost charged against income for these plans was $1.9 million, $1.3 million and
$0.9 million for the years ended December 31, 2008, 2007 and 2006, respectively. It is currently
our policy to purchase units in the open market instead of issuing new units for settlement of
restricted unit grants. At December 31, 2008, 350,000 units were authorized to be granted under
the equity-based compensation plans, of which 226,268 had not yet been granted.
Restricted Units
Under our Long-Term Incentive Plan, we grant restricted units to selected employees and directors
who perform services for us, with vesting generally over a period of one to five years. Although
full ownership of the units does not transfer to the recipients until the units vest, the
recipients have distribution and voting rights on these units from the date of grant. The vesting
for certain key executives is contingent upon certain earnings per unit targets being realized.
The fair value of each unit of restricted unit awards was measured at the market price as of the
date of grant and is being amortized over the vesting period, including the units issued to the key
executives, as we expect those units to fully vest.
A summary of restricted unit activity and changes during the year ended December 31, 2008 is
presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
Average |
|
|
Aggregate |
|
|
|
|
|
|
|
Average |
|
|
Remaining |
|
|
Intrinsic |
|
|
|
|
|
|
|
Grant-Date |
|
|
Contractual |
|
|
Value |
|
Restricted Units |
|
Grants |
|
|
Fair Value |
|
|
Term |
|
|
($000) |
|
|
Outstanding at January 1, 2008 (not vested) |
|
|
44,711 |
|
|
$ |
44.77 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
27,088 |
|
|
|
38.43 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(740 |
) |
|
|
49.74 |
|
|
|
|
|
|
|
|
|
Vesting and transfer of full ownership to recipients |
|
|
(17,554 |
) |
|
|
45.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 (not vested) |
|
|
53,505 |
|
|
$ |
41.28 |
|
|
1.2 years |
|
$ |
1,142 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There were 17,554 restricted units having a fair value of $0.4 million that were vested and
transferred to recipients of our restricted unit grants during the year ended December 31, 2008.
The total intrinsic value of restricted units that were vested and transferred during the year
ended December 31, 2007 was $0.6 million. There were no restricted units vested or transferred
prior to 2007. As of December 31, 2008, there was $0.6 million of total unrecognized compensation
costs related to nonvested restricted unit grants. That cost is expected to be recognized over a
weighted-average period of 1.2 years.
In 2008, we paid $0.8 million for the purchase of 21,459 of our common units in the open market for
the recipients of all 2008 restricted unit grants.
-75-
Performance Units
Under our Long-Term Incentive Plan, we grant performance units to selected executives and employees
who perform services for us. These performance units are payable upon meeting the performance
criteria over a service period, and generally vest over a period of three years. Our initial
performance grant of 1,514 units in 2005 vested in the first quarter of 2008. Payment was based
upon our unit price and upon our total unitholder return during the requisite period as compared to
the total unitholder return of a selected peer group of partnerships. The amount payable under all
other performance unit grants is based upon the growth in distributions per limited partner unit
during the requisite period. As of December 31, 2008, estimated share payouts for outstanding
nonvested performance unit awards ranged from 125% to 150%.
We granted 14,337 performance units to certain officers in March 2008. These units will vest over
a three-year performance period ending December 31, 2010 and are payable in HEP common units. The
number of units actually earned will be based on the growth of distributions to limited partners
over the performance period, and can range from 50% to 150% of the number of performance units
issued. The fair value of these performance units is based on the grant date closing unit price of
$40.54 and will apply to the number of units ultimately awarded.
A summary of performance unit activity and changes during the year ended December 31, 2008 is
presented below:
|
|
|
|
|
|
|
Payable |
Performance Units |
|
In Units |
|
|
|
|
|
Outstanding at January 1, 2008 (not vested) |
|
|
24,148 |
|
Vesting and payment of units to recipients |
|
|
(1,514 |
) |
Granted |
|
|
14,337 |
|
Forfeited |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 (not vested) |
|
|
36,971 |
|
|
|
|
|
|
There were 1,514 performance units having a fair value of $0.1 million that were vested and
transferred to recipients during the year ended December 31, 2008. There were no payments or units
issued for performance units vesting during the years ended December 31, 2007 and 2006. Based on
the weighted average fair value at December 31, 2008 of $42.10, there was $0.8 million of total
unrecognized compensation cost related to nonvested performance units. That cost is expected to be
recognized over a weighted-average period of 1.5 years.
Note 6: Debt
Credit Agreement
In February 2008, we amended our $100.0 million senior secured revolving credit agreement expiring
in August 2011 to increase the size from $100.0 million to $300.0 million (the Credit Agreement),
which we used to finance the $171.0 million cash portion of the consideration paid for the Crude
Pipelines and Tankage Assets acquired from Holly. Union Bank of California, N.A. is one of the
lenders and serves as administrative agent under this agreement. As of December 31, 2008, we had
$200.0 million outstanding under the Credit Agreement.
The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital
and for general partnership purposes. Advances under the Credit Agreement that are either
designated for working capital or have been used as interim financing to fund capital expenditures
are classified as short-term liabilities. Other advances under the Credit Agreement are classified
as long-term liabilities. In addition, the Credit Agreement is available to fund letters of credit
up to a $50.0 million sub-limit and to fund distributions to unitholders up to a $20.0 million
sub-limit. During the year ended December 31, 2008, we received net advances totaling $29.0
million under the Credit Agreement that were used as interim financing for capital expenditures.
-76-
Our obligations under the Credit Agreement are collateralized by substantially all of our assets.
Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P., our general
partner, and guaranteed by our wholly-owned subsidiaries. However, any recourse to HEP Logistics
Holdings, L.P. would be limited to the extent of their assets, which other than their investment in
HEP, are not significant.
We may prepay all loans at any time without penalty, except for payment of certain breakage and
related costs. We are required to reduce all working capital borrowings under the Credit Agreement
to zero for a period of at least 15 consecutive days in each twelve-month period prior to the
maturity date of the agreement. As of December 31, 2008, we did not have any working capital
borrowings.
Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference
rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to
1.50%) or (b) at a rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable
margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio
of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes,
depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on
the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the
ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At
December 31, 2008, we are subject to a 0.30% commitment fee on the $100.0 million unused portion of
the Credit Agreement. The agreement expires in August 2011. At that time, the agreement will
terminate and all outstanding amounts thereunder will be due and payable.
The Credit Agreement imposes certain requirements on us, including: a prohibition against
distribution to unitholders if, before or after the distribution, a potential default or an event
of default as defined in the agreement would occur; limitations on our ability to incur debt, make
loans, acquire other companies, change the nature of our business, enter a merger or consolidation,
or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense
ratio and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders
will be able to accelerate the maturity of the debt and exercise other rights and remedies.
Additionally, the Credit Agreement contains certain provisions whereby the lenders may accelerate
payment of outstanding debt under certain circumstances.
Senior Notes Due 2015
Our Senior Notes maturing March 1, 2015 are registered with the U.S. Securities and Exchange
Commission (SEC) and bear interest at 6.25% (Senior Notes). 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 Moodys and
Standard & Poors 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 their assets, which other than their investment in
HEP, are not significant.
-77-
The carrying amounts of our long-term debt are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Credit Agreement |
|
$ |
200,000 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
Senior Notes
Principal |
|
|
185,000 |
|
|
|
185,000 |
|
Unamortized discount |
|
|
(2,344 |
) |
|
|
(2,724 |
) |
Fair value hedge interest rate swap |
|
|
|
|
|
|
(841 |
) |
Unamortized premium dedesignated fair value hedge |
|
|
2,137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
184,793 |
|
|
|
181,435 |
|
|
|
|
|
|
|
|
Total debt |
|
|
384,793 |
|
|
|
181,435 |
|
Less net short-term borrowings under credit agreement |
|
|
29,000 |
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
355,793 |
|
|
$ |
181,435 |
|
|
|
|
|
|
|
|
Interest Rate Risk Management
As of December 31, 2008, we have three interest rate swap contracts.
We entered into an interest rate swap to hedge our exposure to the cash flow risk caused by the
effects of LIBOR changes on the $171.0 million Credit Agreement advance that we used to finance our
purchase of the Crude Pipelines and Tankage Assets from Holly. This interest rate swap effectively
converts our $171.0 million LIBOR based debt to fixed rate debt having an interest rate of 3.74%
plus an applicable margin, currently 1.75%, which equaled an effective interest rate of 5.49% as of
December 31, 2008. The maturity date of this swap contract is February 28, 2013. We intend to
renew our Credit Agreement prior to its expiration in August 2011 and continue to finance the
$171.0 million balance until the swap matures.
We have designated this interest rate swap as a cash flow hedge. Based on our assessment of
effectiveness using the change in variable cash flows method, we have determined that this interest
rate swap is effective in offsetting the variability in interest payments on our $171.0 million
variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash
flow hedge to its fair value on a quarterly basis with a corresponding offset to accumulated other
comprehensive income. Also on a quarterly basis, we measure hedge effectiveness by comparing the
present value of the cumulative change in the expected future interest to be paid or received on
the variable leg of our swap against the expected future interest payments on our $171.0 million
variable rate debt. Any ineffectiveness is reclassified from accumulated other comprehensive
income to interest expense. As of December 31, 2008, we had no ineffectiveness on our cash flow
hedge.
We also have an interest rate swap contract that effectively converts interest expense associated
with $60.0 million of our 6.25% Senior Notes from fixed to variable rate debt (Variable Rate
Swap). Under this swap contract, interest on the $60.0 million notional amount is computed using
the three-month LIBOR plus a spread of 1.1575%, which equaled an effective interest rate of 3.36%
as of December 31, 2008. The maturity date of this swap contract is March 1, 2015, matching the
maturity of the Senior Notes.
In October 2008, we entered into an additional interest rate swap contract, effective December 1,
2008, that effectively unwinds the effects of the Variable Rate Swap discussed above, converting
$60.0 million of our hedged long-term debt back to fixed rate debt (Fixed Rate Swap). Under the
Fixed Rate Swap, interest on a notional amount of $60.0 million is computed at a fixed rate of
3.59% versus three-month LIBOR which when added to the 1.1575% spread on the Variable Rate Swap
results in an effective fixed interest rate of 4.75%. The maturity date of this swap contract is
December 1, 2013.
Our interest rate swaps not having a hedge designation are measured quarterly at fair value
either as an asset or a liability in our consolidated balance sheets with a corresponding entry to
interest expense. For the year ended December 31, 2008, we recognized $2.3 million in interest
expense attributable to fair value adjustments to our interest rate swaps.
-78-
Prior to the execution of our Fixed Rate Swap, the Variable Rate Swap was designated as a fair
value hedge of $60.0 million in outstanding principal under the Senior Notes. This hedge met the
requirements to assume no ineffectiveness and was accounted for using the shortcut method of
accounting whereby offsetting fair value adjustments to the underlying swap were made to the
carrying value of the Senior Notes, effectively adjusting the carrying value this $60.0 million to
its fair value. We dedesignated this hedge in October 2008. At this time, the carrying balance of
our Senior Notes included a $2.2 million premium due to the application of hedge accounting until
the dedesignation date. This premium is being amortized as a reduction to interest expense over
the remaining term of the Variable Rate Swap.
We record interest expense equal to the variable rate payments under the swaps. Receipts under the
swap agreements are recorded as a reduction of interest expense.
Additional information on our interest rate swaps is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
|
|
|
Location of |
|
|
|
Interest Rate Swaps |
|
Location |
|
Fair Value |
|
|
Offsetting Balance |
|
Offsetting Amount |
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
Asset |
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-variable interest rate swap $60 million of 6.25% Senior Notes |
|
Other assets |
|
$ |
4,079 |
|
|
Long-term debt |
|
$ |
(2,195 |
) |
|
|
|
|
|
|
|
|
Interest expense |
|
|
(1,884 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,079 |
|
|
|
|
$ |
(4,079 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability |
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedge
$171 million LIBOR
based debt
|
|
Other long-term
liabilities
|
|
$ |
(12,967 |
) |
|
Accumulated other
comprehensive
income
|
|
$ |
12,967 |
|
Variable-to-fixed
interest rate swap
$60 million
|
|
Other long-term
liabilities
|
|
|
(4,166 |
) |
|
Interest expense
|
|
|
4,166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(17,133 |
) |
|
|
|
$ |
17,133 |
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense and Other Debt Information
Interest expense consists of the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on outstanding debt: |
|
|
|
|
|
|
|
|
|
|
|
|
Senior Notes, net of interest on interest rate swaps |
|
$ |
10,454 |
|
|
$ |
11,867 |
|
|
$ |
11,588 |
|
Credit Agreement, net of interest on interest rate swaps |
|
|
8,705 |
|
|
|
|
|
|
|
|
|
Net change in fair value of interest rate swaps |
|
|
2,282 |
|
|
|
|
|
|
|
|
|
Amortization of discount and deferred issuance costs |
|
|
1,002 |
|
|
|
1,008 |
|
|
|
968 |
|
Commitment fees |
|
|
327 |
|
|
|
414 |
|
|
|
500 |
|
|
|
|
|
|
|
|
|
|
|
Total interest incurred |
|
|
22,770 |
|
|
|
13,289 |
|
|
|
13,056 |
|
Less capitalized interest |
|
|
1,007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense |
|
$ |
21,763 |
|
|
$ |
13,289 |
|
|
$ |
13,056 |
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest (1) |
|
$ |
12,464 |
|
|
$ |
12,316 |
|
|
$ |
11,912 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net of cash received under our interest rate swap agreements of $3.8 million
for each of the years ended December 31, 2008, 2007 and 2006. |
The estimated fair value of our Senior Notes was $124.0 million at December 31, 2008.
Note 7: Commitments and Contingencies
We lease certain facilities, pipelines and rights of way under operating leases, most of which
contain renewal options. The right of way agreements have various termination dates through 2053.
-79-
As of December 31, 2008, the minimum future rental commitments under operating leases having
non-cancelable lease terms in excess of one year are as follows:
|
|
|
|
|
Year Ending |
|
|
|
December 31, |
|
$000s |
|
2009 |
|
$ |
6,364 |
|
2010 |
|
|
6,363 |
|
2011 |
|
|
6,346 |
|
2012 |
|
|
6,324 |
|
2013 |
|
|
6,321 |
|
Thereafter |
|
|
22,755 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
54,473 |
|
|
|
|
|
Rental expense charged to operations was $6.6 million, $6.1 million and $5.9 million for the years
ended December 31, 2008, 2007 and 2006, respectively.
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.
Note 8: Significant Customers
All revenues are domestic revenues, of which over 90% are currently generated from our three
largest customers: Holly, Alon and BP Plc (BP). The major concentration of our petroleum
products pipeline systems revenues is derived from activities conducted in the southwest United
States. The following table presents the percentage of total revenues generated by each of these
three customers:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
Holly |
|
|
72 |
% |
|
|
60 |
% |
|
|
59 |
% |
Alon |
|
|
16 |
% |
|
|
27 |
% |
|
|
28 |
% |
BP |
|
|
8 |
% |
|
|
9 |
% |
|
|
9 |
% |
Note 9: Related Party Transactions
Holly and Alon Agreements
As of December 31, 2008, we serve Hollys refineries in New Mexico and Utah under three 15-year
pipeline, terminal and tankage agreements. The substantial majority of our business is devoted to
providing transportation, storage and terminalling services to Holly.
We have an agreement that relates to the pipelines and terminals contributed by Holly to us at the
time of our initial public offering in 2004 and expires in 2019 (the Holly PTA). Our second
agreement with Holly relates to the Intermediate Pipelines acquired from Holly in July 2005 and
expires in 2020 (the Holly IPA). And third, we have the Holly CPTA that relates to the Crude
Pipelines and Tankage Assets acquired from Holly and expires on February 29, 2023.
Under the Holly PTA, Holly IPA and Holly CPTA, Holly agreed to transport and store volumes of
refined product and crude oil on our pipelines and terminal and tankage facilities that result in
minimum annual payments to us. These minimum annual payments or revenues will be adjusted each
year at a percentage change equal to the change in the PPI but will not decrease as a result of a
decrease in the PPI. Under these agreements, the agreed upon tariff rates are adjusted each year
on July 1 at a rate equal to the percentage change in the PPI or FERC index, but generally will not
decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change in the
PPI plus a FERC adjustment factor which is reviewed periodically. Following our July 1, 2008 PPI
rate adjustments, these agreements will result in minimum payments to us of $81.3 million for the
twelve months ended June 30, 2009.
-80-
We also have a 15-year pipelines and terminals agreement with Alon (the Alon PTA), expiring in
2020, under which Alon has agreed to transport on our pipelines and throughput through our
terminals volumes of refined products that results in a minimum level of annual revenue. The
agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage
change in PPI, but not below the initial tariff rate. Following the March 1, 2008 PPI adjustment,
Alons total minimum commitment for the twelve months ending February 28, 2009 is $22.0 million.
If Holly or Alon fail to meet their minimum volume commitments under the agreements in any quarter,
it will be required to pay us in cash the amount of any shortfall by the last day of the month
following the end of the quarter. With the exception of the Holly CPTA, a shortfall payment may be
applied as a credit in the following four quarters after minimum obligations are met.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we
have agreed to expand our refined products pipeline system between Artesia, New Mexico and El Paso,
Texas (the South System). The expansion of the South System includes replacing 85 miles of
8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso
Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and
Phoenix, Arizona and making related modifications. The cost of this project is estimated to be
$48.3 million. Currently, we expect to complete the majority of this project in early 2009.
Under certain provisions of the Omnibus Agreement that we entered with Holly in July 2004 and that
expires in 2019, we pay Holly an annual administrative fee for the provision by Holly or its
affiliates of various general and administrative services to us. Effective March 1, 2008, the
annual fee was increased from $2.1 million to $2.3 million to cover additional general and
administrative services attributable to the operations of our Crude Pipelines and Tankage Assets.
This fee does not include the salaries of pipeline and terminal personnel or the cost of their
employee benefits, which are separately charged to us by Holly. We also reimburse Holly and its
affiliates for direct expenses they incur on our behalf.
In consideration for Hollys assistance in obtaining our joint venture opportunity in a new 95-mile
intrastate pipeline system (the SLC Pipeline) now under construction by Plains All American
Pipeline, L.P. (Plains), we will pay Holly a $2.5 million finders fee upon the closing of our
investment in the joint venture with Plains. See Note 13 for further information on this proposed
joint venture.
|
|
Pipeline, terminal and tankage revenues received from Holly were $85.0 million, $61.0
million and $52.9 million for the years ended December 31, 2008, 2007 and 2006, respectively.
These amounts include revenues received under the Holly PTA, Holly IPA and Holly CPTA. |
|
|
|
Other revenues received from Holly for the year ended December 31, 2007 were $2.7 million
related to our sale of inventory of accumulated terminal overages of refined product. These
overages arose from net product gains at our terminals from the beginning of 2005 through the
third quarter of 2007. In the fourth quarter of 2007, we amended our pipelines and terminals
agreement with Holly to provide that, on a go-forward basis, such terminal overages of refined
product belong to Holly. |
|
|
|
Holly charged general and administrative services under the Omnibus Agreement of $2.2
million for the year ended December 31, 2008 and $2.0 million for each of the years ended
December 31, 2007 and 2006. |
|
|
|
We reimbursed Holly for costs of employees supporting our operations of $13.1 million, $8.5
million and $7.7 million for the years ended December 31, 2008, 2007 and 2006, respectively. |
|
|
|
Holly reimbursed us $0.3 million and $0.2 million for certain costs paid on their behalf
for the years ended December 31, 2007 and 2006, respectively. |
|
|
|
We distributed $25.6 million, $22.8 million and $20.3 million for the years ended December
31, 2008, 2007 and 2006, respectively, to Holly as regular distributions on its subordinated
units, common units and general partner interest. |
-81-
|
|
Our accounts receivable from Holly was $9.4 million and $5.7 million at December 31, 2008
and 2007, respectively. |
|
|
|
Our accounts payable to Holly were $2.2 million and $6.0 million at December 31, 2008 and
2007, respectively. |
|
|
|
Holly failed to meet its minimum volume commitment for each of the fourteen quarters since
inception of the Holly IPA. Through December 31, 2008, we have charged Holly $7.0 million for
these shortfalls of which $0.5 million and zero is included in affiliate accounts receivable
at December 31, 2008 and 2007, respectively. |
|
|
|
Our revenues for the years ended December 31, 2008 and 2007 included shortfalls billed
under the Holly IPA of $1.2 million in 2007 and $2.4 million in 2006, respectively, as Holly
did not exceed its minimum volume commitment in any of the subsequent four quarters in 2008
and 2007. Deferred revenue in the consolidated balance sheets at December 31, 2008 and 2007,
includes $2.4 million and $1.1 million, respectively, relating to the Holly IPA. It is
possible that Holly may not exceed its minimum obligations under the Holly IPA to allow Holly
to receive credit for any of the $2.4 million deferred at December 31, 2008. |
Alon became a related party when it acquired all of our Class B subordinated units in connection
with our acquisition of assets from them on February 28, 2005.
|
|
Pipeline and terminal revenues received from Alon were $11.6 million, $21.8 million and
$18.0 million for the years ended December 31, 2008, 2007 and 2006, respectively, under the
Alon PTA. Additionally, pipeline revenues received under a pipeline capacity lease agreement
with Alon were $7.0 million, $7.1 million and $6.9 million for the years ended December 31,
2008, 2007 and 2006, respectively. |
|
|
|
We distributed $2.8 million, $2.6 million and $2.4 million for the years ended December 31,
2008, 2007 and 2006, respectively, to Alon for distributions on its Class B subordinated
units. |
|
|
|
Included in our accounts receivable trade were $2.5 million and $3.5 million at December
31, 2008 and 2007, respectively, which represented receivable balances from Alon. |
|
|
|
Our revenues for the year ended December 31, 2008 included $2.6 million of shortfalls
billed under the Alon PTA in 2007 as Alon did not exceed its minimum revenue obligation in any
of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at
December 31, 2008 and 2007 includes $13.3 million and $2.6 million, respectively, relating to
the Alon PTA. It is possible that Alon may not exceed its minimum obligations under the Alon
PTA to allow Alon to receive credit for any of the $13.3 million deferred at December 31,
2008. |
BP
We have a 70% ownership interest in Rio Grande and BP owns the other 30%. Due to the ownership
interest and resulting consolidation, BP is a related party to us.
|
|
BPs agreement to ship on the Rio Grande pipeline expired on March 31, 2008. Rio Grande is
currently serving multiple shippers on the pipeline. We recorded revenues from BP of $9.3
million, $9.2 million and $8.4 million for the years ended December 31, 2008, 2007 and 2006,
respectively. |
|
|
|
Rio Grande paid distributions to BP of $1.8 million, $1.3 million and $1.5 million for the
years ended December 31, 2008, 2007 and 2006, respectively. |
|
|
|
Included in our accounts receivable trade at December 31, 2008 and 2007 were $2.5
million and $1.5 million, respectively, which represented the receivable balance of Rio Grande
from BP. |
-82-
Note 10: Partners Equity, Allocations and Cash Distributions
Issuances of units
As partial consideration for our purchase of the Crude Pipelines and Tankage Assets, we issued
217,497 of our common units having a fair value of $9.0 million to Holly. Also, Holly purchased an
additional 2,503 of our common units for $0.1 million and HEP Logistics Holdings, L.P., our general
partner, contributed $0.2 million as an additional capital contribution in order to maintain its 2%
general partner interest.
Holly currently holds 7,000,000 of our subordinated units and 290,000 of our common units, which
constitutes a 46% ownership interest in us, including the 2% general partner interest. The
subordination period applicable to Hollys subordinated units extends until the first day of any
quarter beginning after June 30, 2009 that certain tests based on our exceeding minimum quarterly
distributions are met.
Under our registration statement filed with the SEC using a shelf registration process, we may
offer from time to time up to $1.0 billion of our securities, through one or more prospectus
supplements that would describe, among other things, the specific amounts, prices and terms of any
securities offered and how the proceeds would be used. Any proceeds from the sale of securities
would be used for general business purposes, which may include, among other things, funding
acquisitions of assets or businesses, working capital, capital expenditures, investments in
subsidiaries, the retirement of existing debt and/or the repurchase of common units or other
securities.
Allocations of Net Income
Net income 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 any incentive distributions declared in the period. After the amount of incentive
distributions is allocated to the general partner, the remaining net income for the period is
generally allocated to the partners based on their weighted average ownership percentage during the
period.
Cash Distributions
We consider regular cash distributions to unitholders on a quarterly basis, although there is no
assurance as to the future cash distributions since they are dependent upon future earnings, cash
flows, capital requirements, financial condition and other factors. Our Credit Agreement prohibits
us from making cash distributions if any potential default or event of default, as defined in the
Credit Agreement, occurs or would result from the cash distribution.
Within 45 days after the end of each quarter, we distribute all of our available cash (as defined
in our partnership agreement) to unitholders of record on the applicable record date. The amount
of available cash generally is all cash on hand at the end of the quarter; less the amount of cash
reserves established by our general partner to provide for the proper conduct of our business,
comply with applicable law, any of our debt instruments, or other agreements; or provide funds for
distributions to our unitholders and to our general partner for any one or more of the next four
quarters; plus all cash on hand on the date of determination of available cash for the quarter
resulting from working capital borrowings made after the end of the quarter. Working capital
borrowings are generally borrowings that are made under our revolving Credit Agreement and in all
cases are used solely for working capital purposes or to pay distributions to partners.
We make distributions of available cash from operating surplus for any quarter during any
subordination period in the following manner: firstly, 98% to the common unitholders, pro rata, and
2% to the general partner, until we distribute for each outstanding common unit an amount equal to
the minimum quarterly distribution for that quarter; secondly, 98% to the common unitholders, pro
rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount
equal to any arrearages in payment of the minimum quarterly distribution on the common units for
any prior quarters during the
-83-
subordination period; thirdly, 98% to the subordinated unitholders, pro rata, and 2% to the general
partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly
distribution for that quarter; and thereafter, cash in excess of the minimum quarterly
distributions is distributed to the unitholders and the general partner based on the percentages
below.
The 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 shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage Interest in |
|
|
Total Quarterly Distribution |
|
Distributions |
|
|
Target Amount |
|
Unitholders |
|
General Partner |
Minimum Quarterly Distribution |
|
$ |
0.50 |
|
|
|
98 |
% |
|
|
2 |
% |
First Target Distribution |
|
Up to $0.55 |
|
|
98 |
% |
|
|
2 |
% |
Second Target Distribution |
|
above $0.55 up to $0.625 |
|
|
85 |
% |
|
|
15 |
% |
Third Target distribution |
|
above $0.625 up to $0.75 |
|
|
75 |
% |
|
|
25 |
% |
Thereafter |
|
Above $0.75 |
|
|
50 |
% |
|
|
50 |
% |
The following table presents the allocation of our regular quarterly cash distributions to the
general and limited partners for each period in which declared.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands, except per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest |
|
$ |
1,045 |
|
|
$ |
915 |
|
|
$ |
850 |
|
General partner incentive distribution |
|
|
3,098 |
|
|
|
2,191 |
|
|
|
1,182 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general partner distribution |
|
|
4,143 |
|
|
|
3,106 |
|
|
|
2,032 |
|
Limited partner distribution |
|
|
48,283 |
|
|
|
44,868 |
|
|
|
41,638 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total regular quarterly cash distribution |
|
$ |
52,426 |
|
|
$ |
47,974 |
|
|
$ |
43,670 |
|
|
|
|
|
|
|
|
|
|
|
Cash distribution per unit applicable to
limited partners |
|
$ |
2.96 |
|
|
$ |
2.785 |
|
|
$ |
2.585 |
|
|
|
|
|
|
|
|
|
|
|
On January 27, 2009, we announced a cash distribution for the fourth quarter of 2008 of $0.765 per
unit. The distribution is payable on all common, subordinated, and general partner units on
February 13, 2009 to all unitholders of record on February 5, 2009. The aggregate amount of the
distribution is $13.8 million, including $1.0 million to the general partner as an incentive
distribution.
As a master limited partnership, we distribute our available cash, which has historically exceeded
our net income because depreciation and amortization expense represents a non-cash charge against
income. The result is a decline in partners equity since our regular quarterly distributions have
exceeded our quarterly net income. Additionally, if the assets transferred to us upon our initial
public offering in 2004 and the intermediate pipelines purchased from Holly in 2005 had been
acquired from third parties, our acquisition cost in excess of Hollys basis in the transferred
assets of $157.3 million would have been recorded as increases to our properties and equipment and
intangible assets instead of reductions to our partners equity.
Note 11: Quarterly Financial Data (Unaudited)
Summarized quarterly financial data is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
Total |
|
|
|
|
|
|
(In thousands, except per unit data) |
|
|
|
|
Year ended December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
27,276 |
|
|
$ |
26,775 |
|
|
$ |
29,511 |
|
|
$ |
34,526 |
|
|
$ |
118,088 |
|
Operating income |
|
$ |
11,950 |
|
|
$ |
9,369 |
|
|
$ |
10,998 |
|
|
$ |
15,235 |
|
|
$ |
47,552 |
|
Net income |
|
$ |
7,798 |
|
|
$ |
3,815 |
|
|
$ |
6,621 |
|
|
$ |
7,133 |
|
|
$ |
25,367 |
|
Limited partners interest in net income |
|
$ |
6,977 |
|
|
$ |
3,015 |
|
|
$ |
5,716 |
|
|
$ |
6,116 |
|
|
$ |
21,824 |
|
Net income per limited partner unit basic
and diluted |
|
$ |
0.43 |
|
|
$ |
0.18 |
|
|
$ |
0.35 |
|
|
$ |
0.38 |
|
|
$ |
1.34 |
|
Distributions declared per limited partner unit |
|
$ |
0.725 |
|
|
$ |
0.735 |
|
|
$ |
0.745 |
|
|
$ |
0.755 |
|
|
$ |
2.96 |
|
-84-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
Total |
|
|
|
|
|
|
(In thousands, except per unit data) |
|
|
|
|
Year ended December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
23,872 |
|
|
$ |
27,131 |
|
|
$ |
27,213 |
|
|
$ |
27,191 |
|
|
$ |
105,407 |
|
Operating income |
|
$ |
10,796 |
|
|
$ |
14,450 |
|
|
$ |
14,274 |
|
|
$ |
13,551 |
|
|
$ |
53,071 |
|
Net income |
|
$ |
7,434 |
|
|
$ |
11,006 |
|
|
$ |
10,690 |
|
|
$ |
10,141 |
|
|
$ |
39,271 |
|
Limited partners interest in net income |
|
$ |
6,854 |
|
|
$ |
10,280 |
|
|
$ |
9,896 |
|
|
$ |
9,309 |
|
|
$ |
36,339 |
|
Net income per limited partner unit basic
and diluted |
|
$ |
0.43 |
|
|
$ |
0.64 |
|
|
$ |
0.61 |
|
|
$ |
0.58 |
|
|
$ |
2.26 |
|
Distributions declared per limited partner unit |
|
$ |
0.675 |
|
|
$ |
0.690 |
|
|
$ |
0.705 |
|
|
$ |
0.715 |
|
|
$ |
2.785 |
|
Note 12: Supplemental Guarantor/Non-Guarantor Financial Information
Obligations of Holly Energy Partners, L.P. (Parent) under the 6.25% 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. Rio Grande
(Non-Guarantor), in which we have a 70% ownership interest, is the only subsidiary that has not
guaranteed these obligations.
The following financial information presents condensed consolidating balance sheets, statements of income, and statements of cash flows
of the Parent, the Guarantor Subsidiaries and the Non-Guarantor. The information has been presented as if the
Parent accounted for its ownership in the Guarantor Subsidiaries, and the Guarantor Subsidiaries accounted
for the ownership of the Non-Guarantor, using the equity method of accounting.
-85-
Condensed Consolidating Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
December 31, 2008 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
2 |
|
|
$ |
3,706 |
|
|
$ |
1,561 |
|
|
$ |
|
|
|
$ |
5,269 |
|
Accounts receivable |
|
|
|
|
|
|
13,332 |
|
|
|
1,145 |
|
|
|
|
|
|
|
14,477 |
|
Intercompany accounts receivable (payable) |
|
|
(197,828 |
) |
|
|
197,979 |
|
|
|
(151 |
) |
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
176 |
|
|
|
417 |
|
|
|
|
|
|
|
|
|
|
|
593 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
(197,650 |
) |
|
|
215,434 |
|
|
|
2,555 |
|
|
|
|
|
|
|
20,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties and equipment, net |
|
|
|
|
|
|
257,886 |
|
|
|
32,398 |
|
|
|
|
|
|
|
290,284 |
|
Investment in subsidiaries |
|
|
378,481 |
|
|
|
23,842 |
|
|
|
|
|
|
|
(402,323 |
) |
|
|
|
|
Transportation agreements, net |
|
|
|
|
|
|
122,383 |
|
|
|
|
|
|
|
|
|
|
|
122,383 |
|
Other assets |
|
|
5,300 |
|
|
|
1,382 |
|
|
|
|
|
|
|
|
|
|
|
6,682 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
186,131 |
|
|
$ |
620,927 |
|
|
$ |
34,953 |
|
|
$ |
(402,323 |
) |
|
$ |
439,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY (DEFICIT) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
|
|
|
$ |
7,357 |
|
|
$ |
661 |
|
|
$ |
|
|
|
$ |
8,018 |
|
Accrued interest |
|
|
(27,778 |
) |
|
|
30,623 |
|
|
|
|
|
|
|
|
|
|
|
2,845 |
|
Deferred revenue |
|
|
|
|
|
|
15,658 |
|
|
|
|
|
|
|
|
|
|
|
15,658 |
|
Accrued property taxes |
|
|
|
|
|
|
1,015 |
|
|
|
130 |
|
|
|
|
|
|
|
1,145 |
|
Other current liabilities |
|
|
31,214 |
|
|
|
(29,811 |
) |
|
|
102 |
|
|
|
|
|
|
|
1,505 |
|
Short-term borrowings under credit agreement |
|
|
|
|
|
|
29,000 |
|
|
|
|
|
|
|
|
|
|
|
29,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
3,436 |
|
|
|
53,842 |
|
|
|
893 |
|
|
|
|
|
|
|
58,171 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
184,793 |
|
|
|
171,000 |
|
|
|
|
|
|
|
|
|
|
|
355,793 |
|
Other long-term liabilities |
|
|
|
|
|
|
17,604 |
|
|
|
|
|
|
|
|
|
|
|
17,604 |
|
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,218 |
|
|
|
10,218 |
|
Partners equity (deficit) |
|
|
(2,098 |
) |
|
|
378,481 |
|
|
|
34,060 |
|
|
|
(412,541 |
) |
|
|
(2,098 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity (deficit) |
|
$ |
186,131 |
|
|
$ |
620,927 |
|
|
$ |
34,953 |
|
|
$ |
(402,323 |
) |
|
$ |
439,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
December 31, 2007 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
2 |
|
|
$ |
8,060 |
|
|
$ |
2,259 |
|
|
$ |
|
|
|
$ |
10,321 |
|
Accounts receivable |
|
|
|
|
|
|
10,820 |
|
|
|
1,491 |
|
|
|
|
|
|
|
12,311 |
|
Intercompany accounts receivable (payable) |
|
|
(141,175 |
) |
|
|
141,553 |
|
|
|
(378 |
) |
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
183 |
|
|
|
363 |
|
|
|
|
|
|
|
|
|
|
|
546 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
(140,990 |
) |
|
|
160,796 |
|
|
|
3,372 |
|
|
|
|
|
|
|
23,178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties and equipment, net |
|
|
|
|
|
|
125,383 |
|
|
|
33,217 |
|
|
|
|
|
|
|
158,600 |
|
Investment in subsidiaries |
|
|
353,235 |
|
|
|
25,059 |
|
|
|
|
|
|
|
(378,294 |
) |
|
|
|
|
Transportation agreements, net |
|
|
|
|
|
|
54,273 |
|
|
|
|
|
|
|
|
|
|
|
54,273 |
|
Other assets |
|
|
1,302 |
|
|
|
1,551 |
|
|
|
|
|
|
|
|
|
|
|
2,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
213,547 |
|
|
$ |
367,062 |
|
|
$ |
36,589 |
|
|
$ |
(378,294 |
) |
|
$ |
238,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
|
|
|
$ |
8,499 |
|
|
$ |
533 |
|
|
$ |
|
|
|
$ |
9,032 |
|
Accrued interest |
|
|
(2,932 |
) |
|
|
5,928 |
|
|
|
|
|
|
|
|
|
|
|
2,996 |
|
Deferred revenue |
|
|
|
|
|
|
3,700 |
|
|
|
|
|
|
|
|
|
|
|
3,700 |
|
Accrued property taxes |
|
|
|
|
|
|
1,021 |
|
|
|
156 |
|
|
|
|
|
|
|
1,177 |
|
Other current liabilities |
|
|
6,387 |
|
|
|
(5,661 |
) |
|
|
101 |
|
|
|
|
|
|
|
827 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
3,455 |
|
|
|
13,487 |
|
|
|
790 |
|
|
|
|
|
|
|
17,732 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
181,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
181,435 |
|
Other long-term liabilities |
|
|
841 |
|
|
|
340 |
|
|
|
|
|
|
|
|
|
|
|
1,181 |
|
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,740 |
|
|
|
10,740 |
|
Partners equity |
|
|
27,816 |
|
|
|
353,235 |
|
|
|
35,799 |
|
|
|
(389,034 |
) |
|
|
27,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity |
|
$ |
213,547 |
|
|
$ |
367,062 |
|
|
$ |
36,589 |
|
|
$ |
(378,294 |
) |
|
$ |
238,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-86-
Condensed Consolidating Statement of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year ended December 31, 2008 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
|
|
|
$ |
85,040 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
85,040 |
|
Third parties |
|
|
|
|
|
|
25,077 |
|
|
|
9,266 |
|
|
|
(1,295 |
) |
|
|
33,048 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
110,117 |
|
|
|
9,266 |
|
|
|
(1,295 |
) |
|
|
118,088 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
|
|
|
|
38,936 |
|
|
|
3,629 |
|
|
|
(1,295 |
) |
|
|
41,270 |
|
Depreciation and amortization |
|
|
|
|
|
|
21,529 |
|
|
|
1,360 |
|
|
|
|
|
|
|
22,889 |
|
General and administrative |
|
|
3,819 |
|
|
|
2,561 |
|
|
|
(3 |
) |
|
|
|
|
|
|
6,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,819 |
|
|
|
63,026 |
|
|
|
4,986 |
|
|
|
(1,295 |
) |
|
|
70,536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(3,819 |
) |
|
|
47,091 |
|
|
|
4,280 |
|
|
|
|
|
|
|
47,552 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of subsidiaries |
|
|
38,215 |
|
|
|
2,983 |
|
|
|
|
|
|
|
(41,198 |
) |
|
|
|
|
Interest income (expense) |
|
|
(9,029 |
) |
|
|
(12,621 |
) |
|
|
46 |
|
|
|
|
|
|
|
(21,604 |
) |
Gain on sale of assets |
|
|
|
|
|
|
1,032 |
|
|
|
|
|
|
|
|
|
|
|
1,032 |
|
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,278 |
) |
|
|
(1,278 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,186 |
|
|
|
(8,606 |
) |
|
|
46 |
|
|
|
(42,476 |
) |
|
|
(21,850 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
25,367 |
|
|
|
38,485 |
|
|
|
4,326 |
|
|
|
(42,476 |
) |
|
|
25,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
|
|
|
|
(270 |
) |
|
|
(65 |
) |
|
|
|
|
|
|
(335 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
25,367 |
|
|
$ |
38,215 |
|
|
$ |
4,261 |
|
|
$ |
(42,476 |
) |
|
$ |
25,367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year ended December 31, 2007 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
|
|
|
$ |
63,709 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
63,709 |
|
Third parties |
|
|
|
|
|
|
33,720 |
|
|
|
9,217 |
|
|
|
(1,239 |
) |
|
|
41,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
97,429 |
|
|
|
9,217 |
|
|
|
(1,239 |
) |
|
|
105,407 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
|
|
|
|
30,523 |
|
|
|
3,627 |
|
|
|
(1,239 |
) |
|
|
32,911 |
|
Depreciation and amortization |
|
|
|
|
|
|
12,520 |
|
|
|
1,862 |
|
|
|
|
|
|
|
14,382 |
|
General and administrative |
|
|
2,730 |
|
|
|
2,135 |
|
|
|
178 |
|
|
|
|
|
|
|
5,043 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,730 |
|
|
|
45,178 |
|
|
|
5,667 |
|
|
|
(1,239 |
) |
|
|
52,336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(2,730 |
) |
|
|
52,251 |
|
|
|
3,550 |
|
|
|
|
|
|
|
53,071 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of subsidiaries |
|
|
54,362 |
|
|
|
2,487 |
|
|
|
|
|
|
|
(56,849 |
) |
|
|
|
|
Interest income (expense) |
|
|
(12,361 |
) |
|
|
(474 |
) |
|
|
79 |
|
|
|
|
|
|
|
(12,756 |
) |
Gain on sale of assets |
|
|
|
|
|
|
298 |
|
|
|
|
|
|
|
|
|
|
|
298 |
|
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,067 |
) |
|
|
(1,067 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,001 |
|
|
|
2,311 |
|
|
|
79 |
|
|
|
(57,916 |
) |
|
|
(13,525 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
39,271 |
|
|
|
54,562 |
|
|
|
3,629 |
|
|
|
(57,916 |
) |
|
|
39,546 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
|
|
|
|
(200 |
) |
|
|
(75 |
) |
|
|
|
|
|
|
(275 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
39,271 |
|
|
$ |
54,362 |
|
|
$ |
3,554 |
|
|
$ |
(57,916 |
) |
|
$ |
39,271 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year ended December 31, 2006 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
|
|
|
$ |
52,878 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
52,878 |
|
Third parties |
|
|
|
|
|
|
29,119 |
|
|
|
8,400 |
|
|
|
(1,203 |
) |
|
|
36,316 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81,997 |
|
|
|
8,400 |
|
|
|
(1,203 |
) |
|
|
89,194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
|
|
|
|
27,009 |
|
|
|
2,824 |
|
|
|
(1,203 |
) |
|
|
28,630 |
|
Depreciation and amortization |
|
|
|
|
|
|
11,933 |
|
|
|
3,397 |
|
|
|
|
|
|
|
15,330 |
|
General and administrative |
|
|
2,794 |
|
|
|
2,055 |
|
|
|
5 |
|
|
|
|
|
|
|
4,854 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,794 |
|
|
|
40,997 |
|
|
|
6,226 |
|
|
|
(1,203 |
) |
|
|
48,814 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(2,794 |
) |
|
|
41,000 |
|
|
|
2,174 |
|
|
|
|
|
|
|
40,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of subsidiaries |
|
|
42,456 |
|
|
|
1,588 |
|
|
|
|
|
|
|
(44,044 |
) |
|
|
|
|
Interest expense |
|
|
(12,119 |
) |
|
|
(132 |
) |
|
|
94 |
|
|
|
|
|
|
|
(12,157 |
) |
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(680 |
) |
|
|
(680 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
27,543 |
|
|
$ |
42,456 |
|
|
$ |
2,268 |
|
|
$ |
(44,724 |
) |
|
$ |
27,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-87-
Condensed Consolidating Statement of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year Ended December 31, 2008 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Cash flows from operating activities |
|
$ |
44,035 |
|
|
$ |
17,973 |
|
|
$ |
5,843 |
|
|
$ |
(4,200 |
) |
|
$ |
63,651 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to properties and equipment |
|
|
|
|
|
|
(41,762 |
) |
|
|
(541 |
) |
|
|
|
|
|
|
(42,303 |
) |
Acquisition of crude pipelines and tankage
assets |
|
|
|
|
|
|
(171,000 |
) |
|
|
|
|
|
|
|
|
|
|
(171,000 |
) |
Proceeds from sale of assets |
|
|
|
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(212,726 |
) |
|
|
(541 |
) |
|
|
|
|
|
|
(213,267 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net borrowings under credit agreement |
|
|
9,000 |
|
|
|
191,000 |
|
|
|
|
|
|
|
|
|
|
|
200,000 |
|
Proceeds from issuance of common units |
|
|
|
|
|
|
104 |
|
|
|
|
|
|
|
|
|
|
|
104 |
|
Contribution from general partner |
|
|
186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
186 |
|
Distributions to partners |
|
|
(52,426 |
) |
|
|
|
|
|
|
(6,000 |
) |
|
|
6,000 |
|
|
|
(52,426 |
) |
Cash distributions to minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,800 |
) |
|
|
(1,800 |
) |
Purchase of units for restricted unit grants |
|
|
(795 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(795 |
) |
Deferred financing costs |
|
|
|
|
|
|
(705 |
) |
|
|
|
|
|
|
|
|
|
|
(705 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44,035 |
) |
|
|
190,399 |
|
|
|
(6,000 |
) |
|
|
4,200 |
|
|
|
144,564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease for the year |
|
|
|
|
|
|
(4,354 |
) |
|
|
(698 |
) |
|
|
|
|
|
|
(5,052 |
) |
Beginning of year |
|
|
2 |
|
|
|
8,060 |
|
|
|
2,259 |
|
|
|
|
|
|
|
10,321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
2 |
|
|
$ |
3,706 |
|
|
$ |
1,561 |
|
|
$ |
|
|
|
$ |
5,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year Ended December 31, 2007 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Cash flows from operating activities |
|
$ |
49,056 |
|
|
$ |
6,784 |
|
|
$ |
6,226 |
|
|
$ |
(3,010 |
) |
|
$ |
59,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to properties and equipment |
|
|
|
|
|
|
(8,556 |
) |
|
|
(1,401 |
) |
|
|
|
|
|
|
(9,957 |
) |
Proceeds from sale of assets |
|
|
|
|
|
|
325 |
|
|
|
|
|
|
|
|
|
|
|
325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,231 |
) |
|
|
(1,401 |
) |
|
|
|
|
|
|
(9,632 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to partners |
|
|
(47,974 |
) |
|
|
|
|
|
|
(4,300 |
) |
|
|
4,300 |
|
|
|
(47,974 |
) |
Cash distributions to minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,290 |
) |
|
|
(1,290 |
) |
Purchase of units for restricted unit grants |
|
|
(1,082 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,082 |
) |
Deferred financing costs |
|
|
|
|
|
|
(296 |
) |
|
|
|
|
|
|
|
|
|
|
(296 |
) |
Other |
|
|
|
|
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(49,056 |
) |
|
|
(312 |
) |
|
|
(4,300 |
) |
|
|
3,010 |
|
|
|
(50,658 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) for the year |
|
|
|
|
|
|
(1,759 |
) |
|
|
525 |
|
|
|
|
|
|
|
(1,234 |
) |
Beginning of year |
|
|
2 |
|
|
|
9,819 |
|
|
|
1,734 |
|
|
|
|
|
|
|
11,555 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
2 |
|
|
$ |
8,060 |
|
|
$ |
2,259 |
|
|
$ |
|
|
|
$ |
10,321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year Ended December 31, 2006 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Cash flows from operating activities |
|
$ |
44,304 |
|
|
$ |
930 |
|
|
$ |
4,049 |
|
|
$ |
(3,430 |
) |
|
$ |
45,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities additions to
properties and equipment |
|
|
|
|
|
|
(8,881 |
) |
|
|
(226 |
) |
|
|
|
|
|
|
(9,107 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to partners |
|
|
(43,670 |
) |
|
|
|
|
|
|
(4,900 |
) |
|
|
4,900 |
|
|
|
(43,670 |
) |
Cash distributions to minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,470 |
) |
|
|
(1,470 |
) |
Purchase of units for restricted unit grants |
|
|
(634 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(634 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44,304 |
) |
|
|
|
|
|
|
(4,900 |
) |
|
|
3,430 |
|
|
|
(45,774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease for the year |
|
|
|
|
|
|
(7,951 |
) |
|
|
(1,077 |
) |
|
|
|
|
|
|
(9,028 |
) |
Beginning of year |
|
|
2 |
|
|
|
17,770 |
|
|
|
2,811 |
|
|
|
|
|
|
|
20,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
2 |
|
|
$ |
9,819 |
|
|
$ |
1,734 |
|
|
$ |
|
|
|
$ |
11,555 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-88-
Note 13: Proposed Joint Venture
In November 2007, we executed a definitive agreement with Plains to acquire a 25% joint venture
interest in a new 95-mile intrastate pipeline system now under construction by Plains for the
shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. Under the agreement, the
SLC Pipeline will be owned by a joint venture company that will be owned 75% by Plains and 25% by
us. We expect to purchase our 25% interest in the joint venture in March 2009 when the SLC
Pipeline is expected to become fully operational. The SLC Pipeline will allow various refiners in
the Salt Lake City area, including Hollys Woods Cross Refinery, to ship crude oil into the Salt
Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil from Wyoming
and Utah that is currently flowing on Plains Rocky Mountain Pipeline. The total cost of our
investment in the SLC Pipeline is expected to be $28.0 million, including the $2.5 million finders
fee that is payable to Holly upon the closing of our investment in the SLC Pipeline.
-89-
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
We have had no change in, or disagreement with, our independent registered public accounting firm
on matters involving accounting and financial disclosure.
Item 9A. 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 Exchange Act Rule 13a-15(e)) as of the end of the period covered by
this Annual Report on Form 10-K. Based on that evaluation, the principal executive officer and
principal financial officer concluded that the design and operation of our disclosure controls and
procedures are effective in ensuring that information we are required to disclose in the reports
that we file or submit under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commissions rules and forms.
(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.
See Item 8 for Managements Report on its Assessment of the Companys Internal Control Over
Financial Reporting and Report of the Registered Public Accounting Firm.
Item 9B. Other Information
There have been no events that occurred in the fourth quarter of 2008 that would need to be
reported on Form 8-K that have not been previously reported.
-90-
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Holly Logistic Services, L.L.C., as the general partner of HEP Logistics Holdings, L.P., our
general partner, manages our operations and activities on our behalf. Our general partner is not
elected by our unitholders. Unitholders are not entitled to elect the directors of HLS or directly
or indirectly participate in our management or operation. The sole member of HLS, which is a
subsidiary of Holly, elects our directors to serve until their death, resignation or removal. Our
general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as
general partner, for all of our debts (to the extent not paid from our assets), except for
indebtedness or other obligations that are made specifically non-recourse to it. Whenever
possible, our general partner intends to incur indebtedness or other obligations that are
non-recourse.
Three members of the board of directors of HLS serve on a conflicts committee to review specific
matters that the board believes may involve conflicts of interest. The conflicts committee
determines if the resolution of the conflict of interest is fair and reasonable to us. The members
of the conflicts committee may not be officers or employees of HLS or directors, officers, or
employees of its affiliates, and must meet the independence and experience standards established by
the New York Stock Exchange and the Exchange Act to serve on the audit committee of a board of
directors. Any matters approved by the conflicts committee will be conclusively deemed to be fair
and reasonable to us, approved by all of our partners, and not a breach by our general partner of
any duties it may owe us or our unitholders. In addition, we have an audit committee of three
independent directors that reviews our external financial reporting, selects our independent
registered public accounting firm, and reviews procedures for internal auditing and the adequacy of
our internal accounting controls. We also have a compensation committee consisting of the three
independent directors, which oversees compensation decisions for certain officers of HLS whose time
is fully committed to us and a portion of the long-term incentive compensation of other officers
who only devote part of their time to the matters of HEP and who receive long-term incentive
compensation with respect to their services. The compensation committee also oversees the
compensation plans described below. In addition, we have an executive committee of the board
consisting of one independent director and two directors employed by Holly.
The board of directors of HLS has determined that Messrs. Darling, Pinkerton and Stengel meet the
applicable criteria for independence under the currently applicable rules of the New York Stock
Exchange and under the Exchange Act. These directors serve as the only members of our audit,
conflicts and compensation committees.
Mr. Darling has been selected to preside at regularly scheduled meetings of non-management
directors. Persons wishing to communicate with the non-management directors are invited to email
the Presiding Director at presiding.director@hollyenergypartners.com or write to: Charles
M. Darling, IV, Presiding Director, c/o Secretary, Holly Logistic Services, L.L.C., 100 Crescent
Court, Suite 1600, Dallas, Texas 75201-6915.
The board of directors of HLS held twelve meetings during 2008, with the audit committee, conflicts
committee and compensation committee holding seven, seven and ten meetings, respectively. During
2008, each director attended at least 75% of the total number of meetings of the board. With the
exception of two directors who each was absent from one board meeting, all board members attended
each board meeting in 2008. All committee members attended each committee meeting for the
committees on which they serve.
We are managed and operated by the directors and officers of HLS on behalf of our general partner.
Most of our operational personnel are employees of HLS.
Mr. Clifton spends approximately 25% of his time overseeing the management of our business and
affairs. Messrs. Blair and Cunningham spend all of their time in the management of our business.
The rest of our officers devote approximately one-quarter of their time to us. Our non-management
directors
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devote as much time as is necessary to prepare for and attend board of directors and committee
meetings.
The following table shows information for the current directors and executive officers of HLS.
|
|
|
|
|
|
|
Name |
|
Age |
|
Position with HLS |
Matthew P. Clifton
|
|
|
57 |
|
|
Chairman of the Board and Chief Executive Officer1 |
David G. Blair
|
|
|
50 |
|
|
Senior Vice President |
Bruce R. Shaw
|
|
|
41 |
|
|
Senior Vice President and Chief Financial Officer |
Mark T. Cunningham
|
|
|
49 |
|
|
Vice President, Operations |
Denise C. McWatters
|
|
|
49 |
|
|
Vice President, General Counsel and Secretary |
P. Dean Ridenour
|
|
|
67 |
|
|
Director |
Charles M. Darling, IV
|
|
|
60 |
|
|
Director2 3 4 |
William J. Gray
|
|
|
68 |
|
|
Director |
Jerry W. Pinkerton
|
|
|
68 |
|
|
Director1 2 3 4 |
William P. Stengel
|
|
|
60 |
|
|
Director1 2 3 4 |
|
|
|
1 |
|
Member of the Executive Committee |
|
2 |
|
Member of the Conflicts Committee |
|
3 |
|
Member of the Audit Committee |
|
4 |
|
Member of the Compensation Committee |
Matthew P. Clifton was elected Chairman of our Board, and Chief Executive Officer in March 2004.
He has been employed by Holly for over twenty years. Mr. Clifton served as Hollys Vice President
of Economics, Engineering and Legal Affairs from 1988 to 1991, Senior Vice President of Holly from
1991 to 1995, President of Navajo Pipeline Company, a wholly owned subsidiary of Holly, since its
inception in 1981, President of Holly from 1995 to 2005 and has served as Chief Executive Officer
of Holly since January 1, 2006. Mr. Clifton has also served as a director of Holly since 1995.
David G. Blair was elected Senior Vice President in January 2007. He has been employed by Holly
for over 27 years. Mr. Blair served as Hollys Vice President responsible for Holly Asphalt
Company from February 2005 to December 2006. Mr. Blair was General Manager of the NK Asphalt
Partnership between Koch Materials Company and Navajo Refining Company from July 2000 to February
2005. Mr. Blair was named Vice President, Marketing, Asphalt & Specialty Products in October 1994.
Mr. Blair served in various positions within Holly in crude oil supply, wholesale product
marketing, and supply and trading from 1981 to 1991.
Bruce R. Shaw was elected to the position of Senior Vice President, Chief Financial Officer in
January 2008. Mr. Shaw served on our Board of Directors from April 2007 to April 2008 and as Vice
President, Special Projects for Holly from September 2007 to December 2007. Prior to September
2007, Mr. Shaw briefly left Holly in June 2007 and served as President of Standard Supply and
Distributing Company, Inc. and Bartos Industries, Ltd., two companies that are affiliated with each
other in the heating, ventilation, and air conditioning industry. Mr. Shaw previously served Holly
in various positions including Vice President of Corporate Development from February 2006 to May
2007, Vice President of Crude Purchasing and Corporate Development from February 2005 to February
2006, Vice President of Corporate Development from March 2004 to February 2005, Vice President of
Marketing and Corporate Development from November 2003 to March 2004, Vice President of Corporate
Development from October 2001 to November 2003 and Director of Corporate Development from June 1997
to January 2000. Mr. Shaw also served as Vice President, Corporate Development for HLS from August
2004 to January 2007.
Mark T. Cunningham was elected Vice President of Operations in July of 2007. He has served Holly
as Senior Manager of Special Projects from December 2006 through June 2007 and as Senior Manager of
Integrity Management and EH&S from July 2004 through December 2006. Prior to joining Holly, Mr.
Cunningham served Diamond Shamrock / Ultramar Diamond Shamrock for 20 years in several engineering
and pipeline operations capacities. He began his time with Diamond Shamrock in 1983 and
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served various positions including Senior Design Engineer, Superintendent of Special Projects,
Regional Manager and General Manager of Operations and Director of Operations through April 2003.
Denise C. McWatters was promoted to Vice President, General Counsel and Secretary of Holly Logistic
Services, LLC and Holly Corporation effective May 12, 2008. She joined Holly in October 2007 as
Deputy General Counsel with more than 20 years of legal experience. Ms. McWatters served as the
General Counsel of The Beck Group from May 2005 through October 2007. Prior to joining Beck, Ms.
McWatters was a shareholder in the predecessor to Locke Lord Bissell & Liddell LLP, served as
Counsel in the legal department at Citigroup, N.A. and was a shareholder in Cox Smith Matthews
Incorporated.
P. Dean Ridenour was elected to our Board of Directors in August 2004 and served as Vice President
and Chief Accounting Officer from January 2005 to January 2008. Mr. Ridenour served as Vice
President, Special Projects of Holly Corporation from August 2004 to December 2004 and prior to
becoming a full-time employee, provided full-time consulting services to Holly Corporation
beginning in October 2002. From April 2001 until October 2002, Mr. Ridenour was temporarily
retired. From July 1999 through April 2001, Mr. Ridenour served as Chief Financial Officer and
director of GeoUtilities, Inc., an internet-based superstore for energy, telecom and other utility
services, which was purchased by AES Corporation in March 2000. Mr. Ridenour was employed for 34
years by Ernst & Young LLP, including 20 years as an audit partner, retiring in 1997. Mr. Ridenour
is no longer an officer of HEP.
Charles M. Darling, IV was elected to our Board of Directors in July 2004. Mr. Darling has served
as President of DQ Holdings, L.L.C., a venture capital investment and consulting firm focused
primarily on opportunities in the energy industry, since August 1998. From 1997 to 1998, Mr.
Darling was the President and General Counsel, and was a Director from 1993 to 1998, of DeepTech
International, which was acquired by El Paso Energy Corp. in August 1998. Mr. Darling was also a
Director at Leviathan Gas Pipeline Company from 1993 through 1998. Prior to joining DeepTech in
1997, Mr. Darling practiced law at the law firm of Baker Botts, L.L.P., for over 20 years.
William J. Gray was elected to our Board of Directors in April 2008. Mr. Gray is a private
consultant and served as a director of Holly Corporation from September 1996 until May 2008. He
has also served as a governmental affairs consultant for Holly Corporation since January 2003 and
as a consultant to Holly from October 1999 through September 2001. Until October 1999, Mr. Gray was
Senior Vice President, Marketing and Supply of Holly Corporation. In November 2006, Mr. Gray was
elected to the New Mexico House of Representatives.
Jerry W. Pinkerton was elected to our Board of Directors in July 2004. Since December 2003, Mr.
Pinkerton has been retired. From December 2000 to December 2003, Mr. Pinkerton served as a
consultant to TXU Corp and from August 1997 to December 2000, Mr. Pinkerton served as Controller of
TXU and its U.S. subsidiaries. From August 1988 until its merger with TXU in August 1997, Mr.
Pinkerton served as the Vice President and Chief Accounting Officer of ENSERCH Corporation. Prior
to joining ENSERCH, Mr. Pinkerton was employed for 26 years as an auditor by Deloitte Haskins &
Sells, a predecessor firm of Deloitte & Touche, LLP, including 15 years as an audit partner. Mr.
Pinkerton also sits on the board of directors of Animal Health International, Inc. where he serves
as chairman of its audit committee.
William P. Stengel was elected to our Board of Directors in July 2004. Mr. Stengel has been
retired since May 2003. From 1997 to May 2003, Mr. Stengel served as Managing Director of the
global energy and mining group at Citigroup/Citibank, N.A. From 1973 to 1997, Mr. Stengel served
in various other capacities with Citigroup/Citibank, N.A.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and
persons who beneficially own more than 10% of HEPs units to file certain reports with the SEC and
New York Stock Exchange concerning their beneficial ownership of HEPs equity securities. Based on
a review of these reports, other information available to us and written representations from
reporting persons indicating that no other reports were required, all such reports concerning
beneficial ownership were filed
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in a timely manner by reporting persons during the year ended December 31, 2008, except for two
Form 4s filed on January 9, 2008. These Form 4s related to sales of HEP common units held by
David G. Blair and Stephen J. McDonnell to satisfy tax withholding obligations with respect to the
vesting of certain restricted units on January 1, 2008.
Audit Committee
HLSs audit committee is composed of three directors who are not officers or employees of HEP or
any of its subsidiaries or Holly Corporation or any of its subsidiaries. The board of directors of
HLS has adopted a written charter for the audit committee. The board of directors of HLS has
determined that a member of the audit committee, namely Jerry W. Pinkerton, is an audit committee
financial expert (as defined by the SEC) and has designated Mr. Pinkerton as the audit committee
financial expert. As indicated above, the board of directors of HLS has determined that Mr.
Pinkerton meets the applicable criteria for independence under the currently applicable rules of
the New York Stock Exchange and under the Exchange Act.
The audit committee selects our independent registered public accounting firm and reviews the
professional services they provide. It reviews the scope of the audit performed by the independent
registered public accounting firm, the audit report issued by the independent auditor, HEPs annual
and quarterly financial statements, any material comments contained in the auditors letters to
management, HEPs internal accounting controls and such other matters relating to accounting,
auditing and financial reporting as it deems appropriate. In addition, the audit committee reviews
the type and extent of any non-audit work to be performed by the independent registered public
accounting firm and its compatibility with their continued objectivity and independence.
Report of the Audit Committee for the Year Ended December 31, 2008
Management of Holly Logistic Services, L.L.C. is responsible for Holly Energy Partners, L.P.s
internal controls and the financial reporting process. The audit committee selected Ernst & Young
LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of the
Partnership for the year ended December 31, 2008. Ernst & Young LLP is responsible for performing
an independent audit of Holly Energy Partners, L.P.s consolidated financial statements in
accordance with the standards of the Public Company Accounting Oversight Board and to issue a
report thereon as well as to issue a report on the effectiveness of Holly Energy Partners, L.P.s
internal control over financial reporting. The audit committee monitors and oversees these
processes.
The audit committee has reviewed and discussed Holly Energy Partners, L.P.s audited consolidated
financial statements with management and Ernst & Young LLP. The audit committee has discussed with
Ernst & Young LLP the matters required to be discussed by Statement on Auditing Standards No. 114,
The Auditors Communication With Those Charged With Governance. The audit committee has received
the written disclosures and the letter from Ernst & Young LLP pursuant to Rule 3526 of the Public
Company Accounting Oversight Board, Communication With Audit Committees Governing Independence,
and has discussed with Ernst & Young LLP that firms independence.
The board of directors of our general partner, upon recommendation by the audit committee, has
adopted an audit committee charter, which is available on our website at www.hollyenergy.com. The
charter requires the audit committee to approve in advance all audit and non-audit services to be
provided by our independent registered public accounting firm. All fees for audit, audit-related
and tax services as well as all other fees presented under Item 14 Principal Accountant Fees and
Services were approved by the audit committee in accordance with the charter.
Based on the foregoing review and discussions and such other matters the audit committee deemed
relevant and appropriate, the audit committee recommended to the board of directors that the
audited consolidated financial statements of Holly Energy Partners, L.P. be included in Holly
Energy Partners, L.P.s Annual Report on Form 10-K for the year ended December 31, 2008.
Members of the Audit Committee:
Jerry W. Pinkerton, Chairman
Charles M. Darling, IV
William P. Stengel
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Code of Ethics
HEP has adopted a Code of Business Conduct and Ethics that applies to all officers, directors and
employees, including the companys principal executive officer, principal financial officer, and
principal accounting officer.
Available on our website at www.hollyenergy.com are copies of our Corporate Governance Guidelines,
Audit Committee Charter, Compensation Committee Charter, and Code of Business Conduct and Ethics,
all of which also will be provided in print without charge upon written request to the Vice
President, Investor Relations at: Holly Energy Partners, L.P., 100 Crescent Court, Suite 1600,
Dallas, TX, 75201-6915. The Partnership intends to satisfy the disclosure requirement under Item
5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of its Code of Business
Conduct and Ethics with respect to its principal financial officers by posting such information on
this website.
New York Stock Exchange Certification
In 2008, Mr. Clifton, as the Companys Chief Executive Officer, provided to the New York Stock
Exchange the annual CEO certification regarding the Companys compliance with the New York Stock
Exchanges corporate governance listing standards.
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Item 11. Executive Compensation
DIRECTOR COMPENSATION
Members of the Board of Directors of HLS who also serve as officers or employees of HLS or Holly do
not receive additional compensation in their capacity as directors. The only officers of HLS or
Holly who also served as directors during 2008 were Messrs. Clifton, Shaw and Ridenour. Mr. Shaw
was a director until April, 2008. Mr. Gray was elected to
replace Mr. Shaw as a member of the HLS Board of Directors on April
15, 2008. Mr. Ridenour was an employee of Holly during 2008 until March
31, 2008 when he retired but continued to provide limited services to Holly under a consulting
agreement. Mr. Ridenour is no longer an employee and he no longer serves as an officer of HLS.
In 2008, the compensation for non-employee directors of HLS was: (a) a $50,000 annual cash
retainer, payable in four quarterly installments; (b) $1,500 for attendance at each in-person
meeting of the Board of Directors or a Board committee, a $1,000 meeting fee for attendance at each
telephonic meeting of the Board of Directors or a Board committee that lasts more than thirty
minutes, and a fee of $1,500 per day for each day that a non-employee director attends a strategy
meeting with the HLS management; (c) an annual grant under the Holly Energy Partners, L.P.
Long-Term Incentive Plan (Long-Term Incentive Plan) of restricted HEP units equal in value to
$50,000 on the date of grant, with 100% vesting one year after the date of grant. The Long-Term
Incentive Plan grants are effective on the date they are approved by the Board of Directors and
this date varies each year. A restricted HEP unit is a common unit subject to forfeiture until the
award vests.
Each director receiving restricted HEP units is a unitholder with
respect to all of the restricted HEP units and has the right to
receive all distributions paid with respect to such units.
In addition, the directors who serve as chairpersons of the committees of the Board of
Directors each receive an annual retainer of $10,000, payable in four quarterly installments. On
July 25, 2008, the Board of Directors approved the payment of a cash meeting fee to non-employee
directors for attending any meetings of a committee of the Board of Directors of which the
non-employee director is not a member, when such committee meeting attendance is at the request of
the chairman of the committee, with the amount of such meeting fee being the same as the meeting
fee payable to non-employee directors who are committee members in attendance at the same meeting.
Directors are reimbursed for out-of-pocket expenses in connection with attending board or committee
meetings. Each director is fully indemnified by HLS for actions associated with being a director
to the extent permitted under Delaware law.
During the calendar year ending December 31, 2008, compensation was made to directors of HLS as set
forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fees Earned or |
|
Stock |
|
|
|
|
Paid in Cash(1) |
|
Awards(2) |
|
Total |
Charles M. Darling, IV |
|
$ |
101,000 |
|
|
$ |
57,711 |
|
|
$ |
158,711 |
|
William Gray (3) |
|
$ |
40,000 |
|
|
$ |
26,101 |
|
|
$ |
66,101 |
|
Jerry W. Pinkerton |
|
$ |
101,000 |
|
|
$ |
57,711 |
|
|
$ |
158,711 |
|
P. Dean Ridenour (4) |
|
$ |
47,500 |
|
|
$ |
27,838 |
(2) |
|
$ |
75,338 |
|
Bruce R. Shaw (5) |
|
|
0 |
|
|
$ |
29,063 |
|
|
$ |
29,063 |
|
William P. Stengel |
|
$ |
101,000 |
|
|
$ |
57,711 |
|
|
$ |
158,711 |
|
|
|
|
(1) |
|
The number in the chart reflects total 2008 cash compensation. An insignificant
portion of this amount was paid in January, 2009, due to a delay in processing payment
for certain December meeting fees. |
|
(2) |
|
Reflects the amount recognized in the year ended December 31, 2008 in
accordance with Statement of Financial Accounting Standards (SFAS) No. 123(R), Share
Based payments, and includes amounts for awards granted prior to 2008. Messrs.
Stengel, Pinkerton and Darling each received an award of 1,466 restricted HEP units on
August 1, 2008 with a grant date fair value of $50,000. Mr. Gray received an award of
1,833 restricted HEP units on August 1, 2008 with a grant date fair value of $62,500.
Mr. Ridenour received an award of 1,955 restricted HEP units on August 1, 2008 with a
grant date fair value of $66,667. The equity awards to Mr. Gray and Mr. Ridenour
include additional compensation ($12,500 and $16,667, respectively) for service as
outside directors during the period that commenced |
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|
|
|
|
|
after the award of restricted units to directors on August 1, 2007 but prior to the
award of restricted units to directors on August 1, 2008. The restricted HEP units
granted on August 1, 2008 will vest on August 1, 2009. The fair market value of each
restricted unit grant is measured on the grant date and is amortized over the vesting
period. As of December 31, 2008, Messrs. Darling, Pinkerton and Stengel each held
1,466 unvested restricted units, Mr. Gray held 1,833 unvested restricted units and Mr.
Ridenour held 1,955 unvested restricted units. |
|
(3) |
|
In addition to the $40,000 of director fees reflected in
this table, Mr. Gray received cash compensation for consulting
services provided by Mr. Gray to Holly Corporation during 2008.
None of the consulting fees were paid by HEP. |
|
(4) |
|
The director compensation described for P. Dean Ridenour is also included in the Summary
Compensation Table since Mr. Ridenour was one of our officers
through January 7, 2008. |
|
(5) |
|
This represents 2008 amounts accrued for the 2007 restricted HEP units awarded
to Mr. Shaw while he was an outside director. Mr. Shaw was not paid for services as a
director in 2008 since he was also an officer. |
COMPENSATION DISCUSSION AND ANALYSIS
This compensation discussion and analysis (CD&A) provides information about our compensation
objectives and policies for the HLS officers that also act as our principal executive officer, our
principal financial officer and our other most highly compensated executive officers and is
intended to place in perspective the information contained in the executive compensation tables
that follow this discussion. We provide a general description of our compensation program and
specific information about its various components. Additionally, we describe our policies relating
to reimbursement to Holly for compensation expenses. We also provide information about HLS
executive officer changes that became effective in January 2008, where applicable. Immediately
following this CD&A is our Compensation Committee Report (the Committee Report).
Overview
HEP is managed by HLS, the general partner of HEPs general partner. HLS is a subsidiary of Holly.
The employees providing services to HEP are employed by HLS; HEP itself has no employees. As of
December 31, 2008, HLS had 121 employees that provide general, administrative and operational
services to HEP. Throughout this discussion, the following individuals are referred to as the
Named Executive Officers and are included in the Summary Compensation Table:
Matthew P. Clifton, HLSs Chairman of the Board and Chief Executive Officer;
Stephen J. McDonnell, HLSs Vice President and Chief Financial Officer until January 7, 2008
and Assistant to the Chairman from January 7, 2008 through and including January 1, 2009
when he retired;
Bruce R. Shaw, Senior Vice President and Chief Financial Officer effective January 7, 2008;
P. Dean Ridenour, HLSs Vice President and Chief Accounting Officer until January 7, 2008.
Mr. Ridenour continued to serve as a Holly employee until his retirement on March 31, 2008
and no longer served as an officer of HLS. He continues to provide limited services to
Holly pursuant to a consulting agreement and is a member of the Board of Directors of HLS,
but he is no longer an HLS or Holly employee.
David G. Blair, HLSs Senior Vice President; and
Mark T. Cunningham, HLSs Vice President, Operations.
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Of the six Named Executive Officers of HEP, only Messrs. Blair and Cunningham are current employees
of HLS.
Under the terms of the Omnibus Agreement, the annual administrative fee we pay to Holly increased
to $2,300,000 as of March 1, 2008 and is for the provision of general and administrative services
for our benefit, which may be increased as permitted under the Omnibus Agreement. Additionally, we
reimburse Holly for expenses incurred on our behalf. The administrative services covered by the
Omnibus Agreement include, without limitation, the costs of corporate services provided to HEP by
Holly such as accounting, information technology, human resources and in-house legal support;
office space, furnishings and equipment; and transportation of HEP executive officers and employees
on Holly airplanes for business purposes. The partnership agreement provides that our general
partner will determine the expenses that are allocable to HEP. See Item 13, Certain Relationships
and Related Transactions of this Form 10-K Annual Report for additional discussion of our
relationships and transactions with Holly. None of the services covered by the administrative fee
are assigned any particular value individually. Although certain Named Executive Officers provide
services to both Holly and HEP, no portion of the administrative fee is specifically allocated to
services provided by the Named Executive Officers to HEP; rather, the administrative fee generally
covers services provided to HEP by Holly and HLS employees and, except as described below, there is
no reimbursement by HEP of cash compensation expenses paid by Holly or HLS to the Named Executive
Officers. With respect to equity compensation paid by HEP to the Named Executive Officers, HLS
purchases the units, and HEP reimburses HLS for the purchase price.
With respect to Messrs. Blair and Cunningham, we reimbursed Holly for 100% of the compensation
expenses incurred by Holly for salary, bonus, retirement and other benefits for 2008 for Messrs.
Blair and Cunningham. We reimbursed HLS for 100% of the expenses incurred in providing Messrs.
Blair and Cunningham with long-term equity incentive compensation. All compensation paid to them
is fully disclosed in the tabular disclosure following this CD&A.
Messrs. Clifton, McDonnell, Shaw and Ridenour were compensated by HLS for the services they perform
for HLS through awards of equity-based compensation granted pursuant to the Long-Term Incentive
Plan. None of the cash compensation paid to or other benefits made available to Messrs. Clifton,
McDonnell, Shaw and Ridenour by Holly was allocated to the services they provide to HLS and,
therefore, only the Long-Term Incentive Plan awards granted to them are disclosed herein. In 2008,
Mr. Ridenour did not receive HEP equity awards for employee service but did receive equity awards
for service as a director.
Objectives of Compensation Program
Our compensation program is designed to attract and retain talented and productive executives who
are motivated to protect and enhance the long-term value of HEP for its unitholders. Our objective
is to be competitive with our industry and encourage high levels of performance.
The HLS Compensation Committee (the Committee), comprised entirely of independent directors,
administers the Long-Term Incentive Plan for certain HLS employees and reviewed and confirmed in
February 2008 the recommendations of the Holly Compensation Committee with regard to the total
compensation of Messrs. Clifton, McDonnell and Shaw. The Committee determined and approved the
long-term equity incentive compensation to be paid to the Named Executive Officers and the
compensation in addition to the long-term equity incentive compensation to be paid to Mr. Blair.
As to Mr. Blair, the Committee has not adopted any formal policies for allocating compensation
among salaries, bonuses and long-term equity incentive compensation. The Committee attempts to
balance the use of both cash and equity compensation in the total compensation package provided to
Mr. Blair and as to our other Named Executive Officers, attempts to utilize long-term equity
incentive compensation to build value to both HEP and its unitholders. The Committee considers
recommendations by management and many other factors in deciding on the final compensation factors
for which it has responsibility for each Named Executive Officer. The Committee does not review or
approve pension benefits for Named Executive Officers and all are provided the same pension
benefits that are provided to Holly employees.
-98-
Mr. Cunninghams position is a grade that does not require Committee approval of cash compensation,
so his compensation package is reviewed and approved by management instead of the Committee. Mr.
Cunninghams compensation is established by Messrs. Clifton and Blair with the assistance of the
Vice President of Human Resources based upon all of the same factors used by the Committee and
described below. The Committee was provided with an overview of Mr. Cunninghams compensation with
opportunity to request changes to the compensation and the Committee completed its review and
agreed with managements recommendations.
In February 2008, the Committee, with the assistance of management, sought to designate an
appropriate mix of cash and long-term equity incentive compensation for Messrs. Blair and
Cunningham with a goal to provide sufficient current compensation to retain them, while at the same
time providing incentives to maximize long-term value for HEP and its unit holders. The Committee,
with the assistance of management, an