Form 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2010
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 whether the registrant has submitted electronically and posted on its
corporate web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files).
Yes o No o
Indicate by check mark 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 definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
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Large accelerated filer o
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Accelerated filer þ
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Non-accelerated filer o
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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 $640 million on June 30, 2010, 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 11, 2011 was
22,078,509.
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. Forward looking statements
use words such as anticipate, project, expect, plan, goal, forecast, intend, could,
believe, may, and similar expressions and statements regarding our plans and objectives for
future operations. These statements are based on our beliefs and assumptions and those of our
general partner using currently available information and expectations as of the date hereof, are
not guarantees of future performance and involve certain risks and uncertainties. Although we and
our general partner believe that such expectations reflected in such forward-looking statements are
reasonable, neither we nor our general partner can give assurance that our expectations will prove
to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions.
If one or more of these risks or uncertainties materialize, or if underlying assumptions prove
incorrect, our actual results may vary materially from those anticipated, estimated, projected or
expected. Certain factors could cause actual results to differ materially from results anticipated
in the forward-looking statements. These factors include, but are not limited to:
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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 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, the
forward-looking statements that are referred to above. When considering forward-looking
statements, you should keep in mind the risk factors and other cautionary statements set forth in
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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6.25% Senior Notes |
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58 |
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8.25% Senior Notes |
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58 |
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Alon |
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5 |
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Alon PTA |
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8 |
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Amended Credit Agreement |
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11 |
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Beeson Pipeline |
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7 |
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Bpd |
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10 |
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Bpsd |
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7 |
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CFR |
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11 |
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Credit Agreement |
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57 |
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Distributable cash flow |
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46 |
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DOT |
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11 |
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EBITDA |
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46 |
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Expansion capital expenditures |
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10 |
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FERC |
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8 |
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Fixed Rate Swap |
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66 |
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GAAP |
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46 |
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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 ATA |
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7 |
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Holly CPTA |
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8 |
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Holly ETA |
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8 |
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Holly IPA |
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8 |
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Holly NPA |
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8 |
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Holly PTA |
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8 |
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Holly PTTA |
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6 |
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Holly RPA |
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8 |
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LIBOR |
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62 |
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Long-Term Incentive Plan |
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83 |
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LPG |
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6 |
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Maintenance capital expenditures |
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47 |
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mbbls |
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35 |
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mbpd |
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54 |
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Mid-America |
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36 |
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NuStar |
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40 |
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Omnibus Agreement |
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9 |
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OSHA |
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21 |
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Plains |
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7 |
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PPI |
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8 |
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Rio Grande |
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7 |
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Roadrunner Pipeline |
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7 |
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SEC |
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5 |
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Senior Notes |
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16 |
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Sinclair |
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6 |
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Sinclair Transportation |
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41 |
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SLC Pipeline |
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5 |
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Variable Rate Swap |
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66 |
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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 engaged principally in
the business of operating a system of petroleum product and crude oil pipelines, storage tanks,
distribution terminals and loading rack facilities in west Texas, New Mexico, Utah, Arizona,
Oklahoma and Idaho. We were formed in Delaware in 2004 and 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 own and operate petroleum product and crude oil pipelines and terminal, tankage and loading rack
facilities that support Holly Corporations (Holly) refining and marketing operations in west
Texas, New Mexico, Utah, Oklahoma, Idaho and Arizona. Holly currently owns a 34% interest in us
including the 2% general partner interest. We also own and operate refined product pipelines and
terminals, located primarily in Texas, that service Alon USA, Inc.s (Alon) refinery in Big
Spring, Texas. Additionally, we own a 25% joint venture interest in a 95-mile intrastate crude oil
pipeline system (the SLC Pipeline) that serves refineries in the Salt Lake City area.
We generate revenues by charging tariffs for transporting petroleum products and crude oil through
our pipelines, by charging fees for terminalling refined products and other hydrocarbons, and
storing and providing other services at our storage tanks and terminals. We do not take ownership
of products that we transport, terminal or store, and therefore, we are not directly exposed to
changes in commodity prices.
Our assets include:
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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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three 65-mile intermediate pipelines that transport intermediate feedstocks and crude
oil from Hollys Navajo refinery crude oil distillation and vacuum facilities in Lovington,
New Mexico to its petroleum refinery facilities in Artesia, New Mexico; |
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approximately 960 miles of crude oil trunk, gathering and connection pipelines located
in west Texas, New Mexico and Oklahoma 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 located near Salt Lake City, Utah; and |
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gasoline and diesel connecting pipelines located at Hollys Tulsa east refinery
facility. |
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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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a refined product truck loading rack facility at each of Hollys Navajo and Woods Cross
refineries, an asphalt truck loading rack facility at the Navajo refinery Lovington, New
Mexico facility, refined product and lube oil rail loading racks and a lube oil truck
loading rack at Hollys Tulsa refinery west facility and a refined product, asphalt and
liquefied petroleum gas (LPG) truck loading rack, a truck unloading rack and a rail
loading rack at Hollys Tulsa refinery east facility; |
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a Roswell, New Mexico jet fuel terminal leased through September 2011; |
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on-site crude oil tankage at Hollys Navajo, Woods Cross and Tulsa refineries having an
aggregate storage capacity of approximately 600,000 barrels; and |
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on-site refined product and hydrocarbon tankage at Hollys Tulsa refinery having an
aggregate storage capacity of approximately 3,400,000 barrels. |
We also own a 25% joint venture interest in the SLC Pipeline, a 95-mile intrastate pipeline system
that serves refineries in the Salt Lake City area.
We have a long-term strategic relationship with Holly. Our growth plan is to continue to pursue
purchases of logistic assets at its existing refining locations in New Mexico, Utah and Oklahoma.
We will also work with Holly on logistic asset acquisitions in conjunction with Hollys refinery
acquisition strategies. Furthermore, we will continue to pursue third-party logistic asset
acquisitions which are accretive to our unitholders and increase the diversity of our revenues.
2010 Acquisitions
Tulsa East / Lovington Storage Asset Transaction
On March 31, 2010, we acquired from Holly certain storage assets for $88.6 million consisting of
hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail
loading rack and a truck unloading rack located at Hollys Tulsa refinery east facility.
In connection with this purchase, we amended our 15-year pipeline, tankage and loading rack
throughput agreement with Holly (the Holly PTTA) that initially pertained to the logistics and
storage assets acquired from an affiliate of Sinclair Oil Company (Sinclair) in December 2009.
Under the amended Holly PTTA, Holly has agreed to transport, throughput and load volumes of product
through our Tulsa east facility logistics and storage assets that will result in minimum annualized
revenues to us of $27.2 million.
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Also, as part of this same transaction, we acquired Hollys asphalt loading rack facility located
at its Navajo refinery facility in Lovington, New Mexico for $4.4 million and entered into a
15-year asphalt facility throughput agreement (the Holly ATA). Under the Holly ATA, Holly has
agreed to throughput a minimum volume of products via our Lovington asphalt loading rack facility
that will result in minimum annualized revenues to us of $0.5 million.
2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, we acquired from Sinclair storage tanks having approximately 1.4 million
barrels of storage capacity and loading racks at its refinery located in Tulsa, Oklahoma for $79.2
million. The purchase price consisted of $25.7 million in cash, including $4.2 million in taxes
paid and 1,373,609 of our common units having a fair value of $53.5 million. Separately, Holly,
also a party to the transaction, acquired Sinclairs Tulsa refinery.
Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, we acquired from Holly two newly constructed pipelines for $46.5 million,
consisting of a 65-mile, 16-inch crude oil pipeline (the Roadrunner Pipeline) that connects the
Navajo refinery Lovington facility to a terminus of Centurion Pipeline L.P.s pipeline extending
between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects our
New Mexico crude oil gathering system to the Navajo refinery Lovington facility (the Beeson
Pipeline).
Tulsa West Loading Racks Transaction
On August 1, 2009, we acquired from Holly certain truck and rail loading/unloading facilities
located at Hollys Tulsa refinery west facility for $17.5 million. The racks load refined products
and lube oils produced at the Tulsa refinery onto rail cars and/or tanker trucks.
Lovington-Artesia Pipeline Transaction
On June 1, 2009, we acquired from Holly a newly constructed, 16-inch intermediate pipeline for
$34.2 million that runs 65 miles from the Navajo refinerys crude oil distillation and vacuum
facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico.
SLC Pipeline Joint Venture Interest
On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a 95-mile
intrastate pipeline system that we jointly own with Plains All American Pipeline, L.P. (Plains).
The total cost of our investment in the SLC Pipeline was $28 million, consisting of the capitalized
$25.5 million joint venture contribution and the $2.5 million finders fee paid to Holly that was
expensed as acquisition costs.
Holly Capacity Expansion
Also in March 2009 Holly, our largest customer, completed a 15,000 barrels per stream day (bpsd)
capacity expansion of its Navajo refinery increasing refining capacity to 100,000 bpsd, or by 18%.
Rio Grande Pipeline Sale
On December 1, 2009, we sold our 70% interest in Rio Grande Pipeline Company (Rio Grande) to a
subsidiary of Enterprise Products Partners LP for $35 million. Results of operations of Rio Grande
and the $14.5 million gain on the sale are presented in discontinued operations.
2008 Acquisition
Crude Pipelines and Tankage Transaction
On February 29, 2008, we acquired from Holly certain crude pipelines and tankage assets for $180
million, consisting of crude oil trunk lines that support the Navajo refinery, crude oil and
refined product pipelines that support the Woods Cross refinery, on-site crude tankage located at
the Navajo and Woods Cross refinery complexes, a jet fuel products pipeline between Artesia and
Roswell, New Mexico and a
leased jet fuel terminal in Roswell, New Mexico. The consideration paid consisted of $171 million
in cash and 217,497 of our common units having a fair value of $9 million.
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Agreements with Holly and Alon
We serve Hollys refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline
and terminal, tankage and throughput agreements:
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Holly PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to
assets contributed to us by Holly upon our initial public offering in 2004); |
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Holly IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to
assets acquired from Holly in 2005 and 2009); |
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Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that
relates to assets acquired from Holly in 2008); |
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Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024
that relates to the Tulsa east facilities acquired from Sinclair in 2009 and from Holly in
March 2010); |
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Holly RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner
Pipeline acquired from Holly in 2009); |
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Holly ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa
west facilities acquired from Holly in 2009); |
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Holly NPA (natural gas pipeline throughput agreement expiring in 2024); and |
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Holly ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to
the Lovington rack facility acquired from Holly in March 2010). |
Under these agreements, Holly agreed to transport, store and throughput volumes of refined product
and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in
minimum annual payments to us. These minimum annual payments or revenues are adjusted each year at
a percentage change based upon the change in the Producer Price Index (PPI) but will not decrease
as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are
adjusted each year on July 1 at a rate based upon the percentage change in the PPI or Federal
Energy Regulatory Commission (FERC) index, but with the exception of the Holly IPA, generally
will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change
in the PPI plus a FERC adjustment factor that is reviewed periodically.
We also have a pipelines and terminals agreement with Alon expiring in 2020 (the Alon PTA) under
which Alon has agreed to transport on our pipelines and throughput through our terminals volumes of
refined products that result in a minimum level of annual revenue. The agreed upon tariff rates
are increased or decreased annually at a rate equal to the percentage change in PPI, but not below
the initial tariff rate.
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. A shortfall payment under the Holly PTA, Holly IPA and Alon PTA
may be applied as a credit in the following four quarters after minimum obligations are met.
We also have a capacity lease agreement with Alon under which we lease Alon space on our Orla to El
Paso pipeline for the shipment of up to 17,500 barrels of refined product per day. The terms under
this agreement expire beginning in 2012 through 2018.
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At December 31, 2010, 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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Year of |
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Agreement |
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(in millions) |
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Maturity |
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Contract Type |
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Holly PTA |
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$ |
43.7 |
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2019 |
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Minimum revenue commitment |
Holly IPA |
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20.7 |
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2024 |
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Minimum revenue commitment |
Holly CPTA |
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28.4 |
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2023 |
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Minimum revenue commitment |
Holly PTTA |
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27.2 |
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2024 |
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Minimum revenue commitment |
Holly RPA |
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9.2 |
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2024 |
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Minimum revenue commitment |
Holly ETA |
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2.7 |
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2024 |
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Minimum revenue commitment |
Holly ATA |
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0.5 |
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2025 |
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Minimum revenue commitment |
Holly NPA |
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0.6 |
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2024 |
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Minimum revenue commitment |
Alon PTA |
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22.7 |
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2020 |
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Minimum volume commitment |
Alon capacity lease |
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6.6 |
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Various |
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Capacity lease |
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Total |
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$ |
162.3 |
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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.
Omnibus Agreement
We entered into an omnibus agreement with Holly in 2004 that Holly and we have amended and restated
several times in connection with our past acquisitions from Holly with the last amendment and
restatement occurring on March 31, 2010 (the Omnibus Agreement). Under certain provisions of the
Omnibus Agreement, we pay Holly an annual administrative fee for the provision by Holly or its
affiliates of various general and administrative services to us, currently $2.3 million. This fee
includes expenses incurred by Holly and its affiliates to perform centralized corporate functions,
such as executive management, legal, accounting, treasury, 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 agreed to indemnify us up to certain aggregate amounts for any
environmental noncompliance and remediation liabilities associated with assets transferred to us
and occurring or existing prior to the date of such transfers. The transfers that are covered by
the agreement include the refined product pipelines, terminals and tanks transferred by Hollys
subsidiaries in connection with our initial public offering in July 2004, the intermediate
pipelines acquired in July 2005, the crude pipelines and tankage assets acquired in 2008, and the
asphalt loading rack facility acquired in March 2010. The Omnibus Agreement provides environmental
indemnification of up to $15 million for the assets transferred to us, other than the crude
pipelines and tankage assets, plus an additional $2.5 million for the intermediate pipelines
acquired in July 2005. Except as described below, Hollys indemnification obligations described
above will remain in effect for an asset for ten years following the date it is transferred to us.
The Omnibus Agreement also provides an additional $7.5 million of indemnification
through 2023 for environmental noncompliance and remediation liabilities specific to the crude
pipelines and tankage assets. Hollys indemnification obligations described above do not apply to
(i) the Tulsa west loading racks acquired in August 2009, (ii) the 16-inch intermediate pipeline
acquired in June 2009, (iii) the Roadrunner Pipeline, (iv) the Beeson Pipeline, (v) the logistics
and storage assets acquired from Sinclair in December 2009, or (vi) the Tulsa east storage tanks
and loading racks acquired in March 2010.
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Under provisions of the Holly ETA and Holly PTTA, Holly will indemnify us for environmental
liabilities arising from our pre-ownership operations of the Tulsa west loading rack facilities
acquired from Holly in August 2009, the Tulsa logistics and storage assets acquired from Sinclair
in December 2009 and the Tulsa east storage tanks and loading racks acquired from Holly in March
2010. Additionally, Holly agreed to indemnify us for any liabilities arising from Hollys
operation of the loading racks under the Holly ETA.
We have an environmental agreement with Alon with respect to pre-closing environmental costs and
liabilities relating to the pipelines and terminals acquired from Alon in 2005, under which Alon
will indemnify us through 2015, subject to a $100,000 deductible and a $20 million maximum
liability cap.
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, 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 for a
particular capital project may be expended over a period in excess of a year, depending on the time
required to complete the project. Therefore, our planned capital expenditures for a given year
consist of expenditures approved for capital projects included in the current years capital budget
as well as, in certain cases, expenditures approved for capital projects in capital budgets for
prior years. The 2011 capital budget is comprised of $5.8 million for maintenance capital
expenditures and $20.1 million for expansion capital expenditures.
We are currently constructing five interconnecting pipelines between Hollys Tulsa east and west
refining facilities. The project is expected to cost approximately $28 million with completion in
the second quarter of 2011. We are currently negotiating terms for a long-term agreement with
Holly to transfer intermediate products via these pipelines that will commence upon completion of
the project. In the event that we are unable to obtain such an agreement, Holly will reimburse us
for the cost of the pipelines.
We have an option agreement with Holly, granting us an option to purchase Hollys 75% equity
interest in the UNEV Pipeline, a joint venture pipeline currently under construction that will be
capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada.
Under this agreement, we have an option to purchase Hollys equity interest in the UNEV Pipeline,
effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase
price equal to Hollys investment in the joint venture pipeline, plus interest at 7% per annum.
The initial capacity of the pipeline will be 62,000 barrels per day (bpd), with the capacity for
further expansion to 120,000 bpd. The current total cost of the pipeline project including
terminals is expected to be approximately $325
million. This includes the construction of ethanol blending and storage facilities at the Cedar
City terminal. The pipeline is in the final construction phase and is expected to be mechanically
complete in the second quarter of 2011.
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We expect that our currently planned expenditures for sustaining and maintenance capital as well as
expenditures for acquisitions and capital development projects such as the UNEV Pipeline described
above, will be funded with existing cash generated by operations, the sale of additional limited
partner units, the issuance of debt securities and advances under our $275 million senior secured
credit agreement (the Amended Credit Agreement), or a combination thereof. With volatility and
uncertainty at times in the credit and equity markets, there may be limits on our ability to issue
new debt or equity financing. Additionally, due to pricing movements in the debt and equity
markets, we may not be able to issue new debt and equity securities at acceptable pricing. Without
additional capital beyond amounts available under our Amended Credit Agreement, our ability to fund
some of these capital projects may be limited, especially the UNEV Pipeline. We are not obligated
to purchase these assets nor are we subject to any fees or penalties if HLS board of directors
decides not to proceed with any 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 (CFR) 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; 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, Woods Cross and Tulsa refineries, our
contractual relationship with Holly under the Omnibus Agreement and the Holly pipelines and
terminals, tankage and throughput agreements, we believe that we will not face significant
competition for barrels of refined products transported from Hollys refineries, particularly
during the terms of our long-term transportation agreements with Holly expiring in 2019 2025.
Additionally, with our contractual relationship with Alon under the Alon PTA expiring in 2020, we
believe that we will not face significant competition for those barrels of refined products we
transport from Alons Big Spring refinery.
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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.
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 become effective. 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, the Oklahoma
Corporation Commission regulates the rates for intrastate shipments in Oklahoma and the Idaho
Public Utilities Commission regulates the rates for intrastate shipments in Idaho. State
commissions have 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.
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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.
Under the Omnibus Agreement, Holly agreed to indemnify us up to certain aggregate amounts for any
environmental noncompliance and remediation liabilities associated with assets transferred to us
and occurring or existing prior to the date of such transfers. The transfers that are covered by
the agreement include the refined product pipelines, terminals and tanks transferred by Hollys
subsidiaries in connection with our initial public offering in July 2004, the intermediate
pipelines acquired in July 2005, the crude pipelines and tankage assets acquired in 2008, and the
asphalt loading rack facility acquired in March 2010. The Omnibus Agreement provides environmental
indemnification of up to $15 million for the assets transferred to us, other than the crude
pipelines and tankage assets, plus an additional $2.5 million for the intermediate pipelines
acquired in July 2005. Except as described below, Hollys indemnification obligations described
above will remain in effect for an asset for ten years following the date it is transferred to us.
The Omnibus Agreement also provides an additional $7.5 million of indemnification through 2023 for
environmental noncompliance and remediation liabilities specific to the crude pipelines and tankage
assets. Hollys indemnification obligations described above do not apply to (i) the Tulsa west
loading racks acquired in August 2009, (ii) the 16-inch intermediate pipeline acquired in June
2009, (iii) the Roadrunner Pipeline, (iv) the Beeson Pipeline, (v) the logistics and storage assets
acquired from Sinclair in December 2009, or (vi) the Tulsa east storage tanks and loading racks
acquired in March 2010.
Under provisions of the Holly ETA and Holly PTTA, Holly will indemnify us for environmental
liabilities arising from our pre-ownership operations of the Tulsa west loading rack facilities
acquired from Holly in August 2009, the Tulsa logistics and storage assets acquired from Sinclair
in December 2009 and the Tulsa east storage tanks and loading racks acquired from Holly in March
2010. Additionally, Holly agreed to indemnify us for any liabilities arising from Hollys
operation of the loading racks under the Holly ETA.
We have an environmental agreement with Alon with respect to pre-closing environmental costs and
liabilities relating to the pipelines and terminals acquired from Alon in 2005, under which Alon
will indemnify us through 2015, subject to a $100,000 deductible and a $20 million maximum
liability cap.
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.
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There are environmental remediation projects that are currently in progress that relate to certain
assets acquired from Holly. Certain of these projects were underway prior to our purchase and
represent liabilities of Holly Corporation as the obligation for future remediation activities was
retained by Holly. Additionally, as of December 31, 2010, we have an accrual of $0.3 million that
relates to environmental clean-up projects for which we have assumed liability. The remaining
projects, including assessment and monitoring activities, are covered under the Holly environmental
indemnification discussed above and 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 148 people who provide direct support to our operations.
HLS 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.
The headings provided in this Item 1A. are for convenience and reference purposes only and shall
not affect or limit the extent or interpretation of the risk factors.
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, 2010, Holly accounted for 80% of the revenues of our petroleum
product and crude pipelines and 83% 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 long-term pipeline and terminal, tankage and
throughput agreements that it has with us or is unable to meet its minimum annual payment
commitment for any reason, including due to prolonged downtime or a shutdown at the Navajo, Woods
Cross or Tulsa refineries, our revenues and cash flow would decline.
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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, 2010, production from the
Navajo refinery accounted for 86% of the throughput volumes transported by our refined product and
crude oil pipelines. The Navajo refinery also received 100% of the petroleum products shipped on
our intermediate pipelines. Operations at the Navajo, Woods Cross or Tulsa refineries 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 U.S.
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 and potential future climate change regulations; |
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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 costs, 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, Woods Cross and Tulsa refineries 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 its refineries.
Furthermore, Hollys obligations under the long-term pipeline and terminal, tankage and throughput
agreements that it has with us 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, 2010, Alon accounted for 12% of the combined revenues of our
petroleum product and crude oil pipelines and of our terminals and truck loading racks, including
revenues we received from Alon under a capacity lease agreement.
A decline in production at Alons Big Spring refinery would materially reduce the volume of refined
products we transport and terminal for Alon and, 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.
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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 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.
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.
Our leverage may limit our ability to borrow additional funds, comply with the terms of our
indebtedness or capitalize on business opportunities.
As of December 31, 2010, the principal amount of our total outstanding debt was $494 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 Amended Credit
Agreement and the indentures for our 6.25% senior notes maturing March 1, 2015 and the 8.25% senior
notes maturing March 15, 2018 (collectively, the 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 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 the Amended
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 purchase and contribution
agreements with Holly with respect to the intermediate pipelines and the crude pipelines and
tankage assets restrict us from selling pipelines and terminals acquired from Holly and from
prepaying borrowings and long-term debt to outstanding balances below $35 million and $171 million
prior to 2015 and 2018, respectively, in each case 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.
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We may not be able to obtain funding on acceptable terms or at all because of volatility and
uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our
future capital needs.
Although the domestic capital markets have shown signs of improvement in recent months, global
financial markets and economic conditions have been, and continue to be, disrupted and volatile due
to a variety of factors, including uncertainty in the financial services sector, low consumer
confidence, continued high unemployment, geopolitical issues and the current weak economic
conditions. In addition, the fixed-income markets have experienced periods of extreme volatility
which have negatively impacted market liquidity conditions. As a result, the cost of raising money
in the debt and equity capital markets has increased substantially at times while the availability
of funds from those markets 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 may increase as many lenders and
institutional investors increase interest rates, enact tighter lending standards, refuse to
refinance existing debt on similar terms or at all and reduce, or in some cases cease, 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 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.
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We are exposed to the credit risks, and certain other risks, of our key customers and vendors.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We
derive a significant portion of our revenues from contracts with key customers, including Holly and
Alon under their respective pipelines and terminals, tankage and throughput agreements. To the
extent that these and other customers may be unable to meet the specifications of their customers,
we would be adversely affected unless we were able to make comparably profitable arrangements with
other customers.
Mergers among our existing customers could provide strong economic incentives for the combined
entities to utilize systems other than ours, and we could experience difficulty in replacing lost
volumes and revenues. Because a significant portion of our operating costs are fixed, a reduction
in volumes would result not only in a reduction of revenues, but also a decline in net income and
cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations
and make distributions to unitholders.
If any of our key customers default on their obligations to us, our financial results could be
adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their
own operating and regulatory risks. In addition, nonperformance by vendors who have committed to
provide us with products or services could result in higher costs or interfere with our ability to
successfully conduct our business.
Any substantial increase in the nonpayment and/or nonperformance by our customers or vendors could
have a material adverse effect on our results of operations and cash flows.
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, owned by
Magellan Midstream Partners, L.P., is an approximately 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.
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 product 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 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.
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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 long-term pipeline and terminal, tankage and throughput
agreements with Holly and Alon expire beginning in 2019 through 2024.
Meeting the requirements of evolving environmental, health and safety laws and regulations,
including those related to climate change, could adversely affect our performance.
Environmental laws and regulations have raised operating costs for the oil and refined products
industry and compliance with such laws and regulations may cause us, Holly and Alon to incur
potentially material capital expenditures associated with the construction, maintenance, and
upgrading of equipment and facilities. We may also be required to address conditions discovered in
the future that require environmental response actions or remediation. Future environmental,
health and safety requirements or changed interpretations of existing requirements, may impose more
stringent requirements on our assets and operations and require us to incur potentially material
expenditures to ensure our continued
compliance. Future developments in federal laws and regulations governing environmental, health and
safety and energy matters are especially difficult to predict.
Currently, various legislative and regulatory measures to address greenhouse gas emissions
(including carbon dioxide, methane and other gases) are in various phases of discussion or
implementation. These include requirements effective January 2010 that require Hollys and Alons
refineries to report emissions of greenhouse gases to the EPA beginning in 2011, and proposed
federal, state, and regional initiatives that require, or could require, us, Holly and Alon to
reduce greenhouse gas emissions from our facilities. Requiring reductions in greenhouse gas
emissions could cause us to incur substantial costs to (i) operate and maintain our facilities,
(ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse
gas emissions programs, including the acquisition or maintenance of emission credits or allowances.
These requirements may also adversely affect Hollys and Alons refinery operations and have an
indirect adverse effect on our business, financial condition and results of our operations.
- 19 -
Requiring a reduction in greenhouse gas emissions and the increased use of renewable fuels
could also decrease demand for refined products, which could have an indirect, but material,
adverse effect on our business, financial condition and results of operations. For example, in
2010, the EPA promulgated a rule establishing greenhouse gas emission standards for new-model
passenger cars, light-duty trucks, and medium-duty passenger vehicles. Also in 2010, the EPA
promulgated a rule establishing greenhouse gas emission thresholds for the permitting of certain
stationary sources, which could require greenhouse emission controls for those sources. These
requirements could have an indirect adverse effect on our business due to reduced demand for crude
oil and refined products, and a direct adverse affect on our business from increased regulation of
our facilities.
Changes in other forms of health and safety regulations are also being considered. New
pipeline safety legislation requiring more stringent spill reporting and disclosure obligations has
been introduced in the U.S. Congress and was recently passed by the U.S. House of Representatives.
The Department of Transportation has also recently proposed legislation providing for more
stringent oversight of pipelines and increased penalties for violations of safety rules, which is
in addition to the Pipeline and Hazardous Materials Safety Administrations announced intention to
strengthen its rules. Such legislative and regulatory changes could have a material effect on our
operations through more stringent and comprehensive safety regulations and higher penalties for the
violation of those regulations.
Significant physical effects of climate change have the potential to damage our facilities, disrupt
our operations and cause us to incur significant costs in preparing for or responding to those
effects.
Climate change could have an effect on the severity of weather (including hurricanes and floods),
sea levels, the arability of farmland, and water availability and quality. If such effects were to
occur, our operations could be adversely affected. Potential adverse effects could include damage
to our facilities from severe weather such as powerful winds or rising waters in low-lying areas,
disruption of our operations, either because of climate-related damage to our facilities or
scale-backs in our operations due to the threat of such effects, and higher operating costs and
less efficient or non-routine operating practices necessitated by potential climatic effects or in
the aftermath of such effects. Significant physical effects of climate change could also affect us
indirectly by disrupting the operations of our customers or by disrupting services or supplies
provided by service companies or suppliers with whom we have a business relationship. We may not be
able to recover through insurance some or any of the costs that may result from potential physical
effects of climate change.
We may be subject to information technology system failures, network disruptions and breaches in
data security.
Information technology system failures, network disruptions (whether intentional by a third party
or due to natural disaster), breaches of network or data security, or disruption or failure of the
network system used to monitor and control pipeline operations could disrupt our operations by
impeding our processing of transactions, our ability to protect customer or company information and
our financial reporting. Our
computer systems, including our back-up systems, could be damaged or interrupted by power outages,
computer and telecommunications failures, computer viruses, internal or external security breaches,
events such as fires, earthquakes, floods, tornadoes and hurricanes, and/or errors by our
employees. Although we have taken steps to address these concerns by implementing sophisticated
network security and internal control measures, there can be no assurance that a system failure or
data security breach will not have a material adverse effect on our financial condition and results
of operations.
- 20 -
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 terminals, tankage and loading rack 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 the Federal Occupational
Safety and Health Administration (OSHA), and comparable state statutes. Any violation of OSHA
could impose substantial costs on us.
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.
We may have additional maintenance costs in the future.
Our pipeline and storage assets are generally long-lived assets, and some of those assets have been
in service for many years. The age and condition of these assets could result in increased
maintenance or remediation expenditures. Any significant increase in these expenditures could
adversely affect our results of operations, financial position or cash flows, as well as our
ability to pay cash distributions. However, we maintain continuing monitoring programs and
maintenance expenditures in an attempt to address such issues.
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 or destruction of property, injury, or extensive property damage, as well as a curtailment or
interruption in our operations. In addition, third-party damage, mechanical malfunctions,
undetected leaks in pipelines, faulty measurement or other errors may result in significant costs
or lost revenues.
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. With our distribution
policy, we do not have the same flexibility as other legal entities to accumulate cash to protect
against underinsured or uninsured losses.
There can be no assurance that insurance will cover all damages and losses resulting from these
types of hazards. We are not fully insured against all risks incident to our business. We are not
insured against all environmental accidents that might occur, other than those considered to be
sudden and accidental. Our business interruption insurance covers only certain lost revenues
arising from physical damage to our facilities and Holly and Alon facilities. If a significant
accident or event occurs that is not fully insured, our operations could be temporarily or
permanently impaired, and our liabilities and expenses could be significant.
- 21 -
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.
We could be subject to damages based on claims brought against us by our customers or lose
customers as a result of the failure of our products to meet certain quality specifications.
A significant portion of our operating responsibility on refined product pipelines is to insure the
quality and purity of the products loaded at our loading racks. If our quality control measures
were to fail, off specification product could be sent out to public gasoline stations. This type
of incident could result in liability claims regarding damages caused by the off specification fuel
or could impact our ability to retain existing customers or to acquire new customers, any of which
could have a material adverse impact on our results of operations 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.
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, Rocky Mountain and Mid-Continent 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, Rocky
Mountain and Mid-Continent 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 on terms
attractive to us or on terms that allow us to obtain appropriate financing. Finally, Holly also
will be subject to integration risks with respect to its Tulsa refining acquisitions and 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.
- 22 -
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.
If a party with an economic interest were to file either a protest of our proposal for increased
rates or a complaint against our existing tariff rates, or the FERC were to initiate an
investigation of our existing rates, then our rates could be subject to detailed review. If our
proposed rate increases 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 rate increases were
determined to be excessive, plus interest. If our existing rates were found to be in excess of our
cost of services, we could be ordered to refund the excess we collected for as far back as two
years prior to the date of the filing of the complaint challenging the rates, and we could be
ordered to reduce our rates prospectively. In 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.
- 23 -
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.
Adverse changes in our credit ratings and risk profile, and that of our general partner, may
negatively affect us.
Our ability to access capital markets is important to our ability to operate our business. Regional
and national economic conditions, increased scrutiny of the energy industry and regulatory changes,
as well as changes in our economic performance, could result in credit agencies reexamining our
credit rating. While credit ratings reflect the opinions of the credit agencies issuing such
ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could
restrict or discontinue our ability to access capital markets at attractive rates, and could result
in an increase in our borrowing costs, a reduced level of capital expenditures and an impact on
future earnings and cash flows.
We are in compliance with all covenants or other requirements set forth in the Amended Credit
Agreement. Further, we do not have any rating downgrade triggers that would automatically
accelerate the maturity dates of any debt. However, a downgrade in our credit rating could
adversely affect our ability to borrow on, renew existing, or obtain access to new financing
arrangements and would increase the cost of such financing arrangements.
The credit and business risk profiles of our general partner, and of Holly as the indirect owner of
our general partner, may be factors in credit evaluations of us as a master limited partnership due
to the
significant influence of our general partner and its indirect owner over our business activities,
including our cash distribution acquisition strategy and business risk profile. Another factor that
may be considered is the financial condition of our general partner and its owners, including the
degree of their financial leverage and their dependence on cash flow from the partnership to
service their indebtedness.
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Alternative financing strategies may not be successful.
Periodically, we will consider the use of alternative financing strategies such as joint venture
arrangements and the sale of non-strategic assets. Joint venture agreements may not share the risks
and rewards of ownership in proportion to the voting interests. Joint venture arrangements may
require us to pay certain costs or to make certain capital investments and we may have little
control over the amount or the timing of these payments and investments. We may not be able to
negotiate terms that adequately reimburse us for our costs to fulfill service obligations for those
joint ventures where we are the operator. In addition, our joint venture partners may be unable to
meet their economic or other obligations and we may be required to fulfill those obligations alone.
We may periodically sell assets or portions of our business. Separating the existing operations
from our assets or operations of which we dispose may result in significant expense and accounting
charges, disrupt our business or divert managements time and attention. We may not achieve
expected cost savings from these dispositions or the proceeds from sales of assets or portions of
our business may be lower than the net book value of the assets sold. We may not be relieved of all
of our obligations related to the assets or businesses sold. These factors could have a material
adverse effect on our revenues, income from operations, cash flows and our quarterly distribution
on our common units.
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 the assets we have acquired or 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. For example, in 2010 we completed the Tulsa east/Lovington storage
assets acquisition. Acquisitions may require substantial capital or the incurrence of substantial
indebtedness. Our capitalization and results of operations may change significantly as a result of
the acquisitions we recently completed or as a result of future acquisitions. Acquisitions and
business expansions involve numerous risks, including difficulties in the assimilation of the
assets and operations of the acquired businesses, inefficiencies and difficulties that arise
because of unfamiliarity with new assets and the businesses associated with them and new geographic
areas and the diversion of managements attention from other business concerns. Further, unexpected
costs and challenges may arise whenever businesses with different operations or management are
combined, and we may experience unanticipated delays in realizing the benefits of an acquisition,
including the assets and businesses we acquired in 2010. Also, following an acquisition, we may
discover previously unknown liabilities associated with the acquired business or assets for which
we have no recourse under applicable indemnification provisions.
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If we are unable to complete capital projects at their expected costs or in a timely manner, or if
the market conditions assumed in our project economics deteriorate, our financial condition,
results of operations, or cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving construction of new
facilities (or improvements and repairs to our existing facilities) could adversely affect our
ability to achieve forecasted operating results. Although we evaluate and monitor each capital
spending project and try to anticipate difficulties that may arise, such delays or cost increases
may arise as a result of factors that are beyond our control, including:
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denial or delay in issuing requisite regulatory approvals and/or permits; |
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unplanned increases in the cost of construction materials or labor; |
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disruptions in transportation of modular components and/or construction materials; |
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severe adverse weather conditions, natural disasters, or other events
(such as equipment malfunctions explosions, fires, spills) affecting
our facilities, or those of vendors and suppliers; |
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shortages of sufficiently skilled labor, or labor disagreements
resulting in unplanned work stoppages; |
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market-related increases in a projects debt or equity financing costs; and/or |
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nonperformance by, or disputes with, vendors, suppliers, contractors,
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If we are unable to complete capital projects at their expected costs or in a timely manner our
financial condition, results of operations, or cash flows could be materially and adversely
affected.
We do not own all of the land on which our pipeline systems and facilities are located. Our
operations could be disrupted if we were to lose or were unable to renew existing rights-of-way.
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 due to a change in the composition of our Board of Directors, or 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.
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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 the pipelines, terminals and tanks transferred to us by Holly in connection with
our initial public offering in 2004, the intermediate pipelines acquired in 2005, the crude
pipelines and tankage assets acquired in 2008, the asphalt loading rack facility acquired in March
2010, and the refined product pipelines, tankage and terminals acquired from Alon in 2005, 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 product pipelines, tankage and terminals acquired
from Alon, and through 2023 for the crude pipelines and tankage assets acquired from Holly.
Additionally, we have entered into agreements with Holly in connection with our acquisition of the
Sinclair Logistics Assets and the Tulsa Loading Racks that provide that Holly will indemnify us for
certain matters arising from the pre-closing ownership or operation of these assets, which
indemnification obligations are not time limited. 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.
Many of our executive officers face conflicts in the allocation of their time to our business.
Our general partner shares officers and administrative personnel with Holly to operate both our
business and Hollys business. Our general partners officers, several of whom are also officers
of Holly, will allocate the time they and the other employees of Holly spend on our behalf and on
behalf of Holly. These officers face conflicts regarding the allocation of their and other
employees time, which may adversely affect our results of operations, cash flows and financial
condition.
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.
Currently, Holly indirectly owns the 2% general partner interest and a 32% limited partner interest
in us and owns and controls the general partner of 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 other 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
would reflect rates that could be obtained in arms-length, third-party transactions; |
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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
these decisions in the best interests of the stockholders of Holly; |
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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. |
- 27 -
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. We can provide no assurance that Holly will continue to provide us the
officers and employees that are necessary for the conduct of our business nor that such provision
will be on terms that are acceptable to us. If Holly fails to provide us with adequate personnel,
our operations could be adversely impacted.
The administrative fee is subject to annual review and 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 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. 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; however, no such person currently exists. 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.
- 28 -
We may issue additional common units without unitholder approval, which would dilute an existing
unitholders ownership interests.
In August 2009, all of the conditions necessary to end the subordination period for the 7,000,000
subordinated units owned by our general partner were met and the units were converted into our
common units on a one-for-one basis. In addition, under our partnership agreement, because the
subordination period for this class of subordinated units has expired, 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, and the Partnership
currently has a shelf registration on file with the SEC pursuant to which it may issue up to $860
million in additional common units.
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. |
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
public offering; |
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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 million; and |
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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 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. |
- 29 -
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 incentive
distributions.
Our general partner has a limited call right that may require a unitholder 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 (which
it does not presently), 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 or that we have not complied with state partnership law.
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.
Further, we conduct business in a number of states. In some of those states the limitations on the
liability of limited partners for the obligations of a limited partnership have not been clearly
established. The unitholders might be held liable for the partnerships obligations as if they
were a general partner if a court or government agency determined that we were conducting business
in the state but had not complied with the states partnership statute.
- 30 -
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
U.S. Internal Revenue Service (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
us being treated as a partnership for federal income tax purposes. As long as we qualify to be
treated as a partnership for federal income tax purposes, we are not subject to federal income tax.
Although a publicly-traded limited partnership is generally treated as a corporation for federal
income tax purposes, a publicly-traded partnership such as us can qualify to be treated as a
partnership for federal income tax purposes so long as for each taxable year at least 90% of its
gross income is derived from specified investments and activities. We believe that we qualify to
be treated as a partnership for federal income tax purposes because we believe that at least 90% of
our gross income for each taxable year has been and is derived from such specified investments and
activities. While we intend to meet this gross income requirement, regardless of our efforts we
may not find it possible to meet, or may inadvertently fail to meet, this gross income requirement.
If we do not meet this gross income requirement for any taxable year and the IRS does not
determine that such failure was inadvertent, we would be treated as a corporation for such taxable
year and each taxable year thereafter. We have not requested, and do not plan to request, a ruling
from the IRS on this or any other tax matter affecting us.
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%. Under
current law, 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, members of Congress have recently considered substantive changes to existing federal
income tax laws that would affect the tax treatment of certain publicly traded partnerships. We
are unable to predict whether any of these potential changes, or other proposals, will ultimately
be enacted into law. 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.
Our partnership agreement allows remedial allocations of income, deduction, gain and loss by us to
account for differences between the tax basis and fair market value of property at the time the
property is contributed or deemed contributed to us and to account for differences between the fair
market value and book basis of our assets existing at the time of issuance of any common units. If
the IRS does not respect our remedial allocations, ratios of taxable income to cash distributions
received by the holders of common units will be materially higher than previously estimated.
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.
- 31 -
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 will generally be treated as partners to whom we allocate taxable income,
which could be different in amount than the cash we distribute, they will be 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 disposes of 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 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.
An investment in common units by tax-exempt entities, such as employee benefit plans and individual
retirement accounts (known as IRAs), Keogh Plans and other retirement plans, regulated investment
companies and non-U.S. persons raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal income tax, including IRAs and other
retirement plans, will be unrelated business taxable income and will be taxable to them.
Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable
effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay
tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult
their tax adviser before investing in our common units.
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 in order to maintain the
uniformity of the economic and tax characteristics of our common units, we have adopted
depreciation and amortization positions that may not conform to all aspects of existing treasury
regulations. These positions may result in an understatement of deductions and losses and an
overstatement of income and gain to our unitholders. For example, we do not amortize certain
goodwill assets, the value of which has been attributed to certain of our outstanding common units.
A subsequent holder of those common units is entitled to an amortization deduction attributable to
that goodwill under Internal Revenue Code Section 743(b). However, because we cannot identify
these common units once they are traded by the initial holder, we do not give any subsequent holder
of a common unit any such amortization deduction. This approach may understate deductions
available to those unitholders who own those common units and may result in those unitholders
reporting that they have a higher tax basis in their units than would be the case if the IRS
strictly applied treasury regulations relating to these depreciation or amortization adjustments.
This, in turn, may result in those unitholders reporting less gain or more loss on a sale of their
units than would be the case if the IRS strictly applied those treasury regulations.
- 32 -
The IRS may challenge the manner in which we calculate our unitholders basis adjustment under
Internal Revenue Code Section 743(b). If so, because neither we nor a unitholder can identify the
common units to which this issue relates once the initial holder has traded them, the IRS may
assert adjustments to all unitholders selling common units within the period under audit as if all
unitholders owned common units with respect to which allowable deductions were not taken. Any
position we take that is inconsistent with applicable treasury regulations may have to be disclosed
on our federal income tax return. This disclosure increases the likelihood that the IRS will
challenge our positions and propose adjustments to some or all of our unitholders. 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. Recently, however, the Department of the
Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to
which a publicly traded partnership may use a similar monthly simplifying convention to allocate
tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the
proration method we have adopted. If the IRS were to challenge our proration 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, such unitholder 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 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.
- 33 -
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 cases when our unitholders are 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
are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in
our capital and profits within a twelve-month period. For purposes of determining whether the 50%
threshold has been met, multiple sales of the same interest will be counted only once. Our
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 may receive two
Schedules K-1) for one fiscal year and may 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 new
partnership for tax purposes. If treated as a new partnership for federal tax purposes, we must
make new tax elections and could be subject to penalties if we are unable to determine that a
termination occurred. The IRS has recently announced a relief procedure whereby if a publicly
traded partnership that has technically terminated requests and the IRS grants special relief,
among other things, the partnership may be permitted to provide only a single Schedule K-1 to
unitholders for the tax years in which the termination occurs.
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 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, 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.
- 34 -
Unitholders may have negative tax consequences if we default on our debt or sell assets.
If we default on any of our debt, our lenders will have the right to sue us for non-payment. Such
an action could cause an investment loss and cause negative tax consequences for unitholders
through the realization of taxable income by unitholders without a corresponding cash distribution.
Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial
debt outstanding and proceeds of the sale were applied to the debt, unitholders could have
increased taxable income without a corresponding cash distribution.
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 three parallel pipelines that originate at the Navajo
refinery Lovington facilities and terminate at its Artesia 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, New Mexico and Oklahoma that deliver crude oil to the 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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2010 |
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2009 |
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2008 |
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2007 |
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2006 |
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Volumes transported for (bpd): |
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Holly |
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324,382 |
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295,039 |
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253,484 |
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142,447 |
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126,929 |
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Third parties(1) |
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38,910 |
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43,709 |
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22,756 |
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46,511 |
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47,551 |
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Total |
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363,292 |
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338,748 |
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276,240 |
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188,958 |
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174,480 |
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Total barrels in thousands (mbbls)(1) |
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132,602 |
|
|
|
123,643 |
|
|
|
101,104 |
|
|
|
68,970 |
|
|
|
63,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We sold our 70% interest in Rio Grande on December 1, 2009. Rio Grande volumes are
excluded. |
- 35 -
The following table sets forth certain operating data for each of our crude oil and petroleum
product 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diameter |
|
|
Approximate
Length |
|
|
Capacity |
|
Origin and Destination |
|
(inches) |
|
|
(miles) |
|
|
(bpd) |
|
|
|
Refined Product Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Artesia, NM to El Paso, TX |
|
|
6 |
|
|
|
156 |
|
|
|
24,000 |
|
Artesia, NM to Orla, TX to El Paso, TX |
|
|
8/12/8 |
|
|
|
214 |
|
|
|
70,000 |
(1) |
Artesia, NM to Moriarty, NM(2) |
|
|
12/8 |
|
|
|
215 |
|
|
|
45,000 |
(3) |
Moriarty, NM to Bloomfield, NM(2) |
|
|
8 |
|
|
|
191 |
|
|
|
|
(3) |
Big Spring, TX to Abilene, TX |
|
|
6/8 |
|
|
|
105 |
|
|
|
20,000 |
|
Big Spring, TX to Wichita Falls, TX |
|
|
6/8 |
|
|
|
227 |
|
|
|
23,000 |
|
Wichita Falls, TX to Duncan, OK |
|
|
6 |
|
|
|
47 |
|
|
|
21,000 |
|
Midland, TX to Orla, TX |
|
|
8/10 |
|
|
|
135 |
|
|
|
25,000 |
|
Artesia, NM to Roswell, NM |
|
|
4 |
|
|
|
36 |
|
|
|
5,300 |
|
Woods Cross, UT |
|
|
10/8 |
|
|
|
8 |
|
|
|
70,000 |
|
Tulsa, OK(4) |
|
|
|
|
|
|
|
|
|
|
|
|
Intermediate Product Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Lovington, NM to Artesia, NM |
|
|
8 |
|
|
|
65 |
|
|
|
48,000 |
|
Lovington, NM to Artesia, NM |
|
|
10 |
|
|
|
65 |
|
|
|
72,000 |
|
Lovington, NM to Artesia, NM |
|
|
16 |
|
|
|
65 |
|
|
|
96,000 |
|
Crude Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Lovington / Artesia, New Mexico |
|
|
Various |
|
|
|
861 |
|
|
|
31,000 |
|
Roadrunner Pipeline |
|
|
16 |
|
|
|
65 |
|
|
|
80,000 |
|
Beeson Pipeline |
|
|
8 |
|
|
|
37 |
|
|
|
35,000 |
|
Woods Cross, Utah |
|
|
12 |
|
|
|
4 |
|
|
|
40,000 |
|
|
|
|
(1) |
|
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. |
|
(2) |
|
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. |
|
(3) |
|
Capacity for this pipeline is reflected in the information for the Artesia to Moriarty
pipeline. |
|
(4) |
|
Tulsa gasoline and diesel fuel connections to Magellans pipeline of less than one mile. |
Holly shipped an aggregate of 71% 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 2010. These pipelines transported 93% of the light refined products produced by
Hollys Navajo refinery in 2010.
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 primarily for the
shipment of refined products produced at the 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.
Refined products produced at the Navajo refinery destined for El Paso are transported on either
this pipeline or our Artesia to Orla to El Paso pipeline.
- 36 -
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:
|
|
|
an 8-inch, 10-mile and a 12-inch, 72-mile segment from the Navajo refinery to Orla,
Texas; |
|
|
|
|
a 12-inch, 124-mile segment from Orla to outside El Paso, Texas; and |
|
|
|
|
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. As mentioned above, refined products
destined to our 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.
Artesia, New Mexico to Moriarty, New Mexico
The Artesia to Moriarty refined product pipeline consists of a 60-mile, 12-inch pipeline from the
Navajo refinery 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 $520,000 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 the Big Spring refinery to the Abilene terminal. Alon is the only
shipper on this pipeline.
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 the 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 the Big Spring refinery from Midland to our tank farm
at Orla. Alon is the only shipper on this pipeline.
- 37 -
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 product pipelines consist of three pipeline segments. The Woods Cross to
Pioneer terminal segment consists of 2 miles of 8-inch pipeline which 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 Hollys 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 the Navajo refinery Lovington facility
to its Artesia facility. Holly is the only shipper on this pipeline.
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 the Navajo refinery Lovington facility to
its Artesia facility. Holly is the only shipper on this pipeline.
16 Pipeline from Lovington, New Mexico to Artesia, New Mexico
The 65-mile, 16-inch diameter pipeline was constructed in 2009. This pipeline is used for the
shipment of intermediate feedstocks and crude oil from the Navajo refinery Lovington facility to
its Artesia facility. Holly is the only shipper on this pipeline.
Lovington / Artesia, New Mexico crude oil pipelines
The crude oil gathering and trunk pipelines deliver crude oil to Hollys Navajo refinery and
consist of 850 miles of 4-inch, 6-inch and 8-inch diameter pipeline. The crude oil trunk pipelines
consist of five pipeline segments that deliver crude oil to the Navajo refinery Lovington facility
and seven pipeline segments that deliver crude oil to the Navajo refinery 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 Hobbs.
The Artesia system crude oil mainlines include seven 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 and a 1-mile, 6-inch pipeline from Abo to Evans Junction.
We operate a 12-mile, 8-inch pipeline from Evans Junction to Artesia, New Mexico that supplies
natural gas to the Navajo refinery Artesia facility.
Roadrunner Pipeline
The Roadrunner crude oil pipeline connects the Navajo refinery Lovington facility to a west Texas
terminal of the Centurion Pipeline that extends to Cushing, Oklahoma. It was constructed in 2009
and consists of 65 miles of 16-inch pipeline. This pipeline is used for the shipment of crude oil
from Cushing to the Navajo refinery Lovington facility.
- 38 -
Beeson Pipeline
The Beeson crude oil pipeline delivers crude oil to the Navajo refinery Lovington facility. It was
constructed in 2009 and consists of 37 miles of 8-inch pipeline. This pipeline ships crude oil
from our crude oil gathering system to the Navajo refinery Lovington facility for processing.
Woods Cross, Utah crude oil pipeline
This 4-mile, 12-inch pipeline is used for the shipment of crude oil from Chevron Pipelines North
Salt Lake City station to the Woods Cross refinery.
REFINED PRODUCT TERMINALS, LOADING RACKS AND REFINERY TANKAGE
Refined Product Terminals and Loading 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:
|
|
|
distribution; |
|
|
|
|
blending to achieve specified grades of gasoline; |
|
|
|
|
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.
The table below sets forth the total average throughput for our refined product terminals in each
of the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
Refined products terminalled for (bpd): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Holly |
|
|
178,903 |
|
|
|
114,431 |
|
|
|
109,539 |
|
|
|
119,910 |
|
|
|
118,202 |
|
Third parties |
|
|
39,568 |
|
|
|
42,206 |
|
|
|
32,737 |
|
|
|
45,457 |
|
|
|
43,285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
218,471 |
|
|
|
156,637 |
|
|
|
142,276 |
|
|
|
165,367 |
|
|
|
161,487 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (mbbls) |
|
|
79,742 |
|
|
|
57,173 |
|
|
|
52,073 |
|
|
|
60,344 |
|
|
|
58,943 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 39 -
The following table outlines the locations of our terminals and their storage capacities, number of
tanks, supply source, and mode of delivery:
|
|
|
|
|
|
|
|
|
|
|
|
|
Storage |
|
|
Number |
|
|
|
|
|
|
Capacity |
|
|
of |
|
Supply |
|
|
Terminal Location |
|
(barrels) |
|
|
Tanks |
|
Source |
|
Mode of Delivery |
El Paso, TX |
|
|
747,000 |
|
|
20 |
|
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 |
Lovington facility asphalt truck rack |
|
|
N/A |
|
|
N/A |
|
Refinery |
|
Truck |
Woods Cross facility truck rack |
|
|
N/A |
|
|
N/A |
|
Refinery |
|
Truck/Pipeline |
Tulsa west facility truck and rail rack |
|
|
N/A |
|
|
N/A |
|
Refinery |
|
Truck/Rail/Pipeline |
Tulsa east facility truck and rail racks |
|
|
25,000 |
|
|
N/A |
|
Refinery |
|
Truck/Rail/Pipeline |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2,471,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 the Navajo refinery Artesia facility
through our Artesia to El Paso and Artesia to Orla to El Paso pipelines and by rail that account
for 93% of the volumes at this terminal. We also receive product from the Big Spring refinery that
accounted for 7% of the volumes at this terminal in 2010. 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 the Navajo refinery 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 the Navajo refinery 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.
Tucson Terminal
We own 100% of the improvements and lease the underlying ground at this terminal. The Tucson
terminal receives light refined products from Kinder Morgans East System pipeline, which
transports refined products from the Navajo refinery 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.
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.
- 40 -
Boise Terminal
We and Sinclair Transportation Company (Sinclair Transportation) each own a 50% interest in the
Boise terminal. Sinclair Transportation 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 Transportation each own a 50% interest in the Burley terminal. Sinclair
Transportation 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 the Big Spring refinery, which accounted for all of
its volumes in 2010. 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 the Big Spring refinery, which accounted for all of
its volumes in 2010. 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 the Navajo refinery, which accounted for all of its volumes in
2010, 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 the Big Spring
refinery that accounted for all of its volumes in 2010. 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.
Artesia Facility Truck Rack
The truck rack at the Navajo refinery 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.
Lovington Facility Asphalt Truck Rack
The asphalt loading rack facility at the Lovington Refinery loads asphalt produced at the Lovington
facility onto tanker trucks. Holly is the only customer of this truck rack.
- 41 -
Woods Cross Facility Truck Rack
The truck rack at the Woods Cross facility loads light refined products produced at the 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.
Tulsa Facilities Truck and Rail Racks
The Tulsa truck and rail loading rack facilities consist of loading racks located at Hollys Tulsa
refinery west and east facilities. Loading racks at the Tulsa refinery west facility consist of
rail racks that load refined products and lube oil produced at the refinery onto rail car and a
truck rack that loads lube oil onto tanker trucks. Loading racks at the Tulsa refinery east
facility consist of truck and rail racks at which we load refined products and off load crude. The
truck racks also load asphalt and LPG.
Refinery Tankage
Our refinery tankage consists of on-site tankage at Hollys Navajo, Woods Cross and Tulsa
refineries. Our refinery tankage derives its revenues from fixed fees or throughput charges in
providing Hollys refining facilities with approximately 4,000,000 barrels of storage.
The following table outlines the locations of our refinery tankage, storage capacity, tankage type
and number of tanks:
|
|
|
|
|
|
|
|
|
|
|
|
|
Storage |
|
|
|
|
Number |
|
|
|
Capacity |
|
|
|
|
of |
|
Refinery Location |
|
(barrels) |
|
|
Tankage Type |
|
Tanks |
|
Artesia, NM |
|
|
166,000 |
|
|
Crude oil |
|
|
2 |
|
Lovington, NM |
|
|
267,000 |
|
|
Crude oil |
|
|
2 |
|
Woods Cross, UT |
|
|
180,000 |
|
|
Crude oil |
|
|
3 |
|
Tulsa, OK |
|
|
3,485,000 |
|
|
Crude oil and refined product |
|
|
59 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
4,098,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. (Removed and Reserved)
- 42 -
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(1) |
|
|
Volume |
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth quarter |
|
$ |
53.74 |
|
|
$ |
49.16 |
|
|
$ |
0.845 |
|
|
|
2,530,800 |
|
Third quarter |
|
$ |
52.16 |
|
|
$ |
42.17 |
|
|
$ |
0.835 |
|
|
|
4,120,000 |
|
Second quarter |
|
$ |
48.17 |
|
|
$ |
38.41 |
|
|
$ |
0.825 |
|
|
|
4,945,100 |
|
First quarter |
|
$ |
44.95 |
|
|
$ |
38.21 |
|
|
$ |
0.815 |
|
|
|
4,583,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth quarter |
|
$ |
41.65 |
|
|
$ |
35.21 |
|
|
$ |
0.805 |
|
|
|
5,548,600 |
|
Third quarter |
|
$ |
40.05 |
|
|
$ |
31.30 |
|
|
$ |
0.795 |
|
|
|
2,296,400 |
|
Second quarter |
|
$ |
33.29 |
|
|
$ |
23.19 |
|
|
$ |
0.785 |
|
|
|
5,544,700 |
|
First quarter |
|
$ |
30.43 |
|
|
$ |
20.96 |
|
|
$ |
0.775 |
|
|
|
2,632,700 |
|
|
|
|
(1) |
|
Represents cash distributions attributable to each of the quarters in the years ended
December 31, 2010 and 2009. Distributions are declared and paid within 45 days following
the close of each quarter. |
The cash distribution for the fourth quarter of 2010 was declared on January 26, 2011 and is
payable on February 14, 2011 to all unitholders of record on February 7, 2011.
As of February 8, 2011, we had approximately 10,300 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 our Amended Credit Agreement, occurs or would result from the cash distribution. The
indenture relating to our 6.25% and 8.25% 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.
We make distributions of available cash from operating surplus for any quarter in the following
manner: 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; and 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, thereafter. Cash in
excess of the minimum
quarterly distributions is distributed to the unitholders and the general partner based on the
percentages below.
- 43 -
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 |
% |
In May 2010, all of the conditions necessary to end the subordination period for the 937,500 Class
B subordinated units originally issued to Alon were met and the units were converted into our
common units on a one-for-one basis.
- 44 -
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands, except per unit data) |
|
Statement Of Income Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
182,097 |
|
|
$ |
146,561 |
|
|
$ |
108,822 |
|
|
$ |
96,190 |
|
|
$ |
80,794 |
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
52,947 |
|
|
|
44,003 |
|
|
|
38,920 |
|
|
|
30,467 |
|
|
|
26,966 |
|
Depreciation and amortization |
|
|
30,682 |
|
|
|
26,714 |
|
|
|
21,937 |
|
|
|
12,920 |
|
|
|
12,833 |
|
General and administrative |
|
|
7,719 |
|
|
|
7,586 |
|
|
|
6,380 |
|
|
|
4,914 |
|
|
|
4,849 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91,348 |
|
|
|
78,303 |
|
|
|
67,237 |
|
|
|
48,301 |
|
|
|
44,648 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
90,749 |
|
|
|
68,258 |
|
|
|
41,585 |
|
|
|
47,889 |
|
|
|
36,146 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of SLC Pipeline |
|
|
2,393 |
|
|
|
1,919 |
|
|
|
|
|
|
|
|
|
|
|
|
|
SLC Pipeline acquisition costs |
|
|
|
|
|
|
(2,500 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
7 |
|
|
|
11 |
|
|
|
118 |
|
|
|
454 |
|
|
|
899 |
|
Interest expense |
|
|
(34,001 |
) |
|
|
(21,501 |
) |
|
|
(21,763 |
) |
|
|
(13,289 |
) |
|
|
(13,056 |
) |
Gain on sale of assets |
|
|
|
|
|
|
|
|
|
|
36 |
|
|
|
298 |
|
|
|
|
|
Other income |
|
|
17 |
|
|
|
67 |
|
|
|
990 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,584 |
) |
|
|
(22,004 |
) |
|
|
(20,619 |
) |
|
|
(12,537 |
) |
|
|
(12,157 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before
income taxes |
|
|
59,165 |
|
|
|
46,254 |
|
|
|
20,966 |
|
|
|
35,352 |
|
|
|
23,989 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
(296 |
) |
|
|
(20 |
) |
|
|
(270 |
) |
|
|
(200 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
58,869 |
|
|
|
46,234 |
|
|
|
20,696 |
|
|
|
35,152 |
|
|
|
23,989 |
|
Income from discontinued operations,
net of noncontrolling interest(1) |
|
|
|
|
|
|
19,780 |
|
|
|
4,671 |
|
|
|
4,119 |
|
|
|
3,554 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
58,869 |
|
|
|
66,014 |
|
|
|
25,367 |
|
|
|
39,271 |
|
|
|
27,543 |
|
Less general partner interest in net income,
including incentive
distributions(2) |
|
|
12,152 |
|
|
|
7,947 |
|
|
|
3,913 |
|
|
|
3,166 |
|
|
|
1,858 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
46,717 |
|
|
$ |
58,067 |
|
|
$ |
21,454 |
|
|
$ |
36,105 |
|
|
$ |
25,685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners per unit interest in net
income basic and diluted(2) |
|
$ |
2.12 |
|
|
$ |
3.18 |
|
|
$ |
1.32 |
|
|
$ |
2.24 |
|
|
$ |
1.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions per limited partner unit |
|
$ |
3.32 |
|
|
$ |
3.16 |
|
|
$ |
3.00 |
|
|
$ |
2.835 |
|
|
$ |
2.635 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(3) |
|
$ |
123,841 |
|
|
$ |
100,707 |
|
|
$ |
70,195 |
|
|
$ |
66,684 |
|
|
$ |
55,030 |
|
Distributable cash flow(4) |
|
$ |
91,054 |
|
|
$ |
72,213 |
|
|
$ |
60,365 |
|
|
$ |
51,012 |
|
|
$ |
47,219 |
|
Cash flows from operating activities |
|
$ |
103,168 |
|
|
$ |
68,195 |
|
|
$ |
63,651 |
|
|
$ |
59,056 |
|
|
$ |
45,853 |
|
Cash flows from investing activities |
|
$ |
(60,629 |
) |
|
$ |
(147,379 |
) |
|
$ |
(213,267 |
) |
|
$ |
(9,632 |
) |
|
$ |
(9,107 |
) |
Cash flows from financing activities |
|
$ |
(44,644 |
) |
|
$ |
76,423 |
|
|
$ |
144,564 |
|
|
$ |
(50,658 |
) |
|
$ |
(45,774 |
) |
Maintenance capital expenditures(4) |
|
$ |
4,487 |
|
|
$ |
3,595 |
|
|
$ |
3,133 |
|
|
$ |
1,863 |
|
|
$ |
1,095 |
|
Expansion capital expenditures |
|
|
56,142 |
|
|
|
150,149 |
|
|
|
210,170 |
|
|
|
8,094 |
|
|
|
8,012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
60,629 |
|
|
$ |
153,744 |
|
|
$ |
213,303 |
|
|
$ |
9,957 |
|
|
$ |
9,107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment |
|
$ |
434,950 |
|
|
$ |
398,044 |
|
|
$ |
257,886 |
|
|
$ |
125,384 |
|
|
$ |
127,357 |
|
Total assets |
|
$ |
643,273 |
|
|
$ |
616,845 |
|
|
$ |
439,688 |
|
|
$ |
238,904 |
|
|
$ |
245,771 |
|
Long-term debt(5) |
|
$ |
491,648 |
|
|
$ |
390,827 |
|
|
$ |
355,793 |
|
|
$ |
181,435 |
|
|
$ |
180,660 |
|
Total liabilities |
|
$ |
533,901 |
|
|
$ |
422,981 |
|
|
$ |
431,568 |
|
|
$ |
200,348 |
|
|
$ |
198,582 |
|
Total equity(6) |
|
$ |
109,372 |
|
|
$ |
193,864 |
|
|
$ |
8,120 |
|
|
$ |
38,556 |
|
|
$ |
47,189 |
|
|
|
|
(1) |
|
On December 1, 2009, we sold our 70% interest in Rio Grande. Results of operations of
Rio Grande and the $14.5 million gain on the sale are presented in discontinued operations. |
- 45 -
|
|
|
(2) |
|
Net income is allocated between limited partners and the general partner interest in
accordance with the provisions of the partnership agreement. Net income allocated to the
general partner includes incentive distributions declared subsequent to quarter end. Net
income attributable to the limited partners is divided by the weighted average limited
partner units outstanding in computing the limited partners per unit interest in net
income. |
|
(3) |
|
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 U.S. generally
accepted accounting principles (GAAP). However, the amounts included in the EBITDA
calculation are derived from amounts included in our consolidated financial statements,
with the exception of EBITDA from discontinued operations. EBITDA should not be considered
as an alternative to net income or operating income, as an indication of our operating
performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA
is not necessarily comparable to similarly titled measures of other companies. EBITDA is
presented here because it is a widely used financial indicator used by investors and
analysts to measure performance. EBITDA 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands) |
|
|
|
|
|
Income from continuing operations |
|
$ |
58,869 |
|
|
$ |
46,234 |
|
|
$ |
20,696 |
|
|
$ |
35,152 |
|
|
$ |
23,989 |
|
|
|
|
|
Add (subtract): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
30,453 |
|
|
|
20,620 |
|
|
|
18,479 |
|
|
|
12,281 |
|
|
|
12,088 |
|
Amortization of discount and deferred
debt issuance costs |
|
|
1,008 |
|
|
|
706 |
|
|
|
1,002 |
|
|
|
1,008 |
|
|
|
968 |
|
Increase in interest expense
change in fair value of interest rate
swaps and swap settlement costs |
|
|
2,540 |
|
|
|
175 |
|
|
|
2,282 |
|
|
|
|
|
|
|
|
|
Interest income |
|
|
(7 |
) |
|
|
(11 |
) |
|
|
(118 |
) |
|
|
(454 |
) |
|
|
(899 |
) |
State income tax |
|
|
296 |
|
|
|
20 |
|
|
|
270 |
|
|
|
200 |
|
|
|
|
|
Depreciation and amortization |
|
|
30,682 |
|
|
|
26,714 |
|
|
|
21,937 |
|
|
|
12,920 |
|
|
|
12,833 |
|
EBITDA from discontinued operations
(excludes gain on sale of Rio Grande in
2009) |
|
|
|
|
|
|
6,249 |
|
|
|
5,647 |
|
|
|
5,577 |
|
|
|
6,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
|
$ |
123,841 |
|
|
$ |
100,707 |
|
|
$ |
70,195 |
|
|
$ |
66,684 |
|
|
$ |
55,030 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4) |
|
Distributable cash flow is not a calculation based upon GAAP. However, the amounts
included in the calculation are derived from amounts separately presented in our
consolidated financial statements, with the exception of equity in excess cash flows over
earnings of SLC Pipeline, maintenance capital expenditures and distributable cash flow from
discontinued operations. Distributable cash flow should not be considered in isolation or
as an alternative to net income or operating income as an indication of our operating
performance or as an alternative to operating cash flow as a measure of liquidity.
Distributable cash flow is not necessarily comparable to similarly titled measures of other
companies. Distributable cash flow is presented here because it is a widely accepted
financial indicator used by investors to compare partnership performance. It also is used
by management for internal analysis and for our performance units. We believe that this
measure provides investors an enhanced perspective of the operating performance of our
assets and the cash our business is generating. |
- 46 -
Set forth below is our calculation of distributable cash flow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
58,869 |
|
|
$ |
46,234 |
|
|
$ |
20,696 |
|
|
$ |
35,152 |
|
|
$ |
23,989 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add (subtract): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
30,682 |
|
|
|
26,714 |
|
|
|
21,937 |
|
|
|
12,920 |
|
|
|
12,833 |
|
Amortization of discount and deferred
debt issuance costs |
|
|
1,008 |
|
|
|
706 |
|
|
|
1,002 |
|
|
|
1,008 |
|
|
|
968 |
|
Increase in interest expense change
in fair value of interest rate swaps
and swap settlement costs |
|
|
2,540 |
|
|
|
175 |
|
|
|
2,282 |
|
|
|
|
|
|
|
|
|
Equity in excess cash flows over
earnings of SLC Pipeline |
|
|
407 |
|
|
|
552 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in deferred revenue |
|
|
2,035 |
|
|
|
(7,256 |
) |
|
|
11,958 |
|
|
|
(1,786 |
) |
|
|
4,473 |
|
SLC Pipeline acquisition costs* |
|
|
|
|
|
|
2,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures** |
|
|
(4,487 |
) |
|
|
(3,595 |
) |
|
|
(3,133 |
) |
|
|
(1,863 |
) |
|
|
(1,095 |
) |
Distributable cash flow from
discontinued operations (excludes gain
on sale of Rio Grande in 2009) |
|
|
|
|
|
|
6,183 |
|
|
|
5,623 |
|
|
|
5,581 |
|
|
|
6,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow |
|
$ |
91,054 |
|
|
$ |
72,213 |
|
|
$ |
60,365 |
|
|
$ |
51,012 |
|
|
$ |
47,219 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Under accounting standards effective January 1, 2009, we were required to
expense rather than capitalize certain acquisition costs of $2.5 million associated
with our joint venture agreement with Plains that closed in March 2009. These costs
directly relate to our interest in the new joint venture pipeline and are similar to
expansion capital expenditures; accordingly, we have added back these costs to arrive
at distributable cash flow. |
|
** |
|
Maintenance capital expenditures are capital expenditures made to replace
partially or fully depreciated assets in order to maintain the existing operating
capacity of our assets and to extend their useful lives. Maintenance capital
expenditures include expenditures required to maintain equipment reliability, tankage
and pipeline integrity, safety and to address environmental regulations. |
|
(5) |
|
Includes $159 million, $206 million and $171 million in credit agreement advances that
were classified as long-term debt at December 31, 2010, 2009 and 2008, respectively. |
|
(6) |
|
As a master limited partnership, we distribute our available cash, which historically
has exceeded our net income because depreciation and amortization expense represents a
non-cash charge against income. The result is a decline in partners equity since our
regular quarterly distributions have exceeded our quarterly net income. Additionally, if
the assets contributed and acquired from Holly while under common control of Holly had been
acquired from third parties, our acquisition cost in excess of Hollys basis in the
transferred assets of $218 million would have been recorded in our financial statements as
increases to our properties and equipment and intangible assets instead of decreases to
partners equity. |
- 47 -
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
Holly Energy Partners, L.P. is a Delaware limited partnership. We own and operate petroleum
product and crude oil pipelines and terminal, tankage and loading rack facilities that support
Hollys refining and marketing operations in west Texas, New Mexico, Utah, Oklahoma, Idaho and
Arizona. Holly currently owns a 34% interest in us. We also own and operate refined product
pipelines and terminals, located primarily in Texas, that service Alons Big Spring refinery in Big
Spring, Texas. Additionally, we own a 25% joint venture interest in the SLC Pipeline, a 95-mile
intrastate crude oil pipeline system that serves refineries in the Salt Lake City area.
We generate revenues by charging tariffs for transporting petroleum products and crude oil through
our pipelines, by charging fees for terminalling refined products and other hydrocarbons and
storing and providing other services at our storage tanks and terminals. We do not take ownership
of products that we transport, terminal or store, and therefore, we are not directly exposed to
changes in commodity prices.
2010 Acquisitions
Tulsa East / Lovington Storage Asset Transaction
On March 31, 2010, we acquired from Holly certain storage assets for $93 million, consisting of
hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail
loading rack and a truck unloading rack located at Hollys Tulsa refinery east facility and an
asphalt loading rack facility located at Hollys Navajo refinery facility in Lovington, New Mexico.
2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, we acquired certain logistics and storage assets for $79.2 million from an
affiliate of Sinclair consisting of storage tanks having approximately 1.4 million barrels of
storage capacity and loading racks at its refinery located in Tulsa, Oklahoma.
Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, we acquired from Holly two newly constructed pipelines for $46.5 million,
consisting of the Roadrunner Pipeline, a 65-mile, 16-inch crude oil pipeline that connects the
Navajo refinery facility located in Lovington, New Mexico to a terminus of Centurion Pipeline
L.P.s pipeline extending between west Texas and Cushing, Oklahoma, and the Beeson Pipeline, a
37-mile, 8-inch crude oil pipeline that connects our New Mexico crude oil gathering system to the
Navajo refinery Lovington facility.
Tulsa West Loading Racks Transaction
On August 1, 2009, we acquired from Holly for $17.5 million certain truck and rail
loading/unloading facilities located at Hollys Tulsa refinery west facility. The racks load
refined products and lube oils produced at the Tulsa refinery onto rail cars and/or tanker trucks.
Lovington-Artesia Pipeline Transaction
On June 1, 2009, we acquired from Holly a newly constructed, 16-inch intermediate pipeline for
$34.2 million that runs 65 miles from the Navajo refinerys crude oil distillation and vacuum
facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico.
- 48 -
SLC Pipeline Joint Venture Interest Transaction
On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile
intrastate pipeline system that we jointly own with Plains. The SLC Pipeline commenced operations
effective March 2009 and allows 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 flowing from Wyoming and Utah via Plains Rocky Mountain
Pipeline. The total cost of our investment in the SLC Pipeline was $28 million, consisting of the
capitalized $25.5 million joint venture contribution and the $2.5 million finders fee paid to
Holly that was expensed as acquisition costs.
Holly Capacity Expansion
Also in March 2009 Holly, our largest customer, completed a 15,000 bpsd capacity expansion of its
Navajo refinery increasing refining capacity to 100,000 bpsd, or by 18%.
Rio Grande Pipeline Sale
On December 1, 2009, we sold our 70% interest in Rio Grande to a subsidiary of Enterprise Products
Partners LP for $35 million. Results of operations of Rio Grande and the $14.5 million gain on the
sale are presented in discontinued operations.
2008 Acquisition
Crude Pipelines and Tankage Transaction
In February 2008, we acquired from Holly certain crude pipelines and tankage assets for $180
million that 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.
Agreements with Holly and Alon
We serve Hollys refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline
and terminal, tankage and throughput agreements:
|
|
|
Holly PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to
assets contributed to us by Holly upon our initial public offering in 2004); |
|
|
|
|
Holly IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to
assets acquired from Holly in 2005 and 2009); |
|
|
|
|
Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that
relates to assets acquired from Holly in 2008); |
|
|
|
|
Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024
that relates to the Tulsa east facilities acquired from Sinclair in 2009 and from Holly in
March 2010); |
|
|
|
|
Holly RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner
Pipeline acquired from Holly in 2009); |
|
|
|
|
Holly ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa
west facilities acquired from Holly in 2009); |
|
|
|
|
Holly NPA (natural gas pipeline throughput agreement expiring in 2024); and |
|
|
|
|
Holly ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to
the Lovington rack facility acquired from Holly in March 2010). |
Under these agreements, Holly agreed to transport, store and throughput volumes of refined product
and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in
minimum annual payments to us. These minimum annual payments or revenues are adjusted each year at
a percentage change based upon 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 based upon the percentage change in the PPI or FERC index, but with the
exception of the Holly IPA, generally will not decrease as a result of a decrease in the PPI or
FERC index. The FERC index is the change in the PPI plus a FERC adjustment factor that is reviewed
periodically.
- 49 -
We also have a pipelines and terminals agreement with Alon expiring in 2020 under which Alon has
agreed to transport on our pipelines and throughput through our terminals volumes of refined
products that result in a minimum level of annual revenue. The agreed upon tariff rates are
increased or decreased annually at a rate equal to the percentage change in PPI, but not below the
initial tariff rate.
We also have a capacity lease agreement with Alon under which we lease Alon space on our Orla to El
Paso pipeline for the shipment of up to 17,500 barrels of refined product per day. The terms under
this agreement expire beginning in 2012 through 2018.
At December 31, 2010, contractual minimums under our long-term service agreements are as follows:
|
|
|
|
|
|
|
|
|
|
|
Minimum Annualized |
|
|
|
|
|
|
|
Commitment |
|
|
|
|
|
Agreement |
|
(In millions) |
|
|
Year of Maturity |
|
Contract Type |
|
|
|
|
|
|
|
|
|
Holly PTA |
|
$ |
43.7 |
|
|
2019 |
|
Minimum revenue commitment |
Holly IPA |
|
|
20.7 |
|
|
2024 |
|
Minimum revenue commitment |
Holly CPTA |
|
|
28.4 |
|
|
2023 |
|
Minimum revenue commitment |
Holly PTTA |
|
|
27.2 |
|
|
2024 |
|
Minimum revenue commitment |
Holly RPA |
|
|
9.2 |
|
|
2024 |
|
Minimum revenue commitment |
Holly ETA |
|
|
2.7 |
|
|
2024 |
|
Minimum revenue commitment |
Holly ATA |
|
|
0.5 |
|
|
2025 |
|
Minimum revenue commitment |
Holly NPA |
|
|
0.6 |
|
|
2024 |
|
Minimum revenue commitment |
Alon PTA |
|
|
22.7 |
|
|
2020 |
|
Minimum volume commitment |
Alon capacity lease |
|
|
6.6 |
|
|
Various |
|
Capacity lease |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
162.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
A significant reduction in revenues under these agreements would have a material adverse effect on
our results of operations.
Under certain provisions of the Omnibus Agreement that we have with Holly, we pay Holly an annual
administrative fee, currently $2.3 million, for the provision by Holly or its affiliates of various
general and administrative services to us. This fee does not include the salaries of pipeline and
terminal personnel or the cost of their employee benefits, which are separately charged to us by
Holly. 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.
- 50 -
RESULTS OF OPERATIONS
The following tables present income, distributable cash flow and volume information for the years
ended December 31, 2010, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended |
|
|
|
|
|
|
December 31, |
|
|
Change from |
|
|
|
2010 |
|
|
2009 |
|
|
2009 |
|
|
|
(In thousands, except per unit data) |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
$ |
48,482 |
|
|
$ |
43,206 |
|
|
$ |
5,276 |
|
Affiliates intermediate pipelines |
|
|
20,998 |
|
|
|
16,362 |
|
|
|
4,636 |
|
Affiliates crude pipelines |
|
|
38,932 |
|
|
|
29,266 |
|
|
|
9,666 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
108,412 |
|
|
|
88,834 |
|
|
|
19,578 |
|
Third parties refined product pipelines |
|
|
27,954 |
|
|
|
37,930 |
|
|
|
(9,976 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
136,366 |
|
|
|
126,764 |
|
|
|
9,602 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
37,964 |
|
|
|
12,561 |
|
|
|
25,403 |
|
Third parties |
|
|
7,767 |
|
|
|
7,236 |
|
|
|
531 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,731 |
|
|
|
19,797 |
|
|
|
25,934 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
182,097 |
|
|
|
146,561 |
|
|
|
35,536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
52,947 |
|
|
|
44,003 |
|
|
|
8,944 |
|
Depreciation and amortization |
|
|
30,682 |
|
|
|
26,714 |
|
|
|
3,968 |
|
General and administrative |
|
|
7,719 |
|
|
|
7,586 |
|
|
|
133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91,348 |
|
|
|
78,303 |
|
|
|
13,045 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
90,749 |
|
|
|
68,258 |
|
|
|
22,491 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of SLC Pipeline |
|
|
2,393 |
|
|
|
1,919 |
|
|
|
474 |
|
SLC Pipeline acquisition costs |
|
|
|
|
|
|
(2,500 |
) |
|
|
2,500 |
|
Interest income |
|
|
7 |
|
|
|
11 |
|
|
|
(4 |
) |
Interest expense, including amortization |
|
|
(34,001 |
) |
|
|
(21,501 |
) |
|
|
(12,500 |
) |
Other |
|
|
17 |
|
|
|
67 |
|
|
|
(50 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,584 |
) |
|
|
(22,004 |
) |
|
|
(9,580 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes |
|
|
59,165 |
|
|
|
46,254 |
|
|
|
12,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
(296 |
) |
|
|
(20 |
) |
|
|
(276 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
58,869 |
|
|
|
46,234 |
|
|
|
12,635 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of noncontrolling interest of $1,579 |
|
|
|
|
|
|
5,301 |
|
|
|
(5,301 |
) |
Gain on sale of interest in Rio Grande |
|
|
|
|
|
|
14,479 |
|
|
|
(14,479 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations |
|
|
|
|
|
|
19,780 |
|
|
|
(19,780 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
58,869 |
|
|
|
66,014 |
|
|
|
(7,145 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Less general partner interest in net income, including incentive distributions(2) |
|
|
12,152 |
|
|
|
7,947 |
|
|
|
4,205 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
46,717 |
|
|
$ |
58,067 |
|
|
$ |
(11,350 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners earnings per unit basic and diluted(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
2.12 |
|
|
$ |
2.12 |
|
|
$ |
|
|
Income from discontinued operations |
|
|
|
|
|
|
0.28 |
|
|
|
(0.28 |
) |
Gain on sale of discontinued operations |
|
|
|
|
|
|
0.78 |
|
|
|
(0.78 |
) |
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
2.12 |
|
|
$ |
3.18 |
|
|
$ |
(1.06 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partners units outstanding |
|
|
22,079 |
|
|
|
18,268 |
|
|
|
3,811 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(3) |
|
$ |
123,841 |
|
|
$ |
100,707 |
|
|
$ |
23,134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow(4) |
|
$ |
91,054 |
|
|
$ |
72,213 |
|
|
$ |
18,841 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes from continuing operations (bpd)(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
|
96,094 |
|
|
|
88,001 |
|
|
|
8,093 |
|
Affiliates intermediate pipelines |
|
|
84,277 |
|
|
|
69,794 |
|
|
|
14,483 |
|
Affiliates crude pipelines |
|
|
144,011 |
|
|
|
137,244 |
|
|
|
6,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
324,382 |
|
|
|
295,039 |
|
|
|
29,343 |
|
Third parties refined product pipelines |
|
|
38,910 |
|
|
|
43,709 |
|
|
|
(4,799 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
363,292 |
|
|
|
338,748 |
|
|
|
24,544 |
|
Terminals and loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
178,903 |
|
|
|
114,431 |
|
|
|
64,472 |
|
Third parties |
|
|
39,568 |
|
|
|
42,206 |
|
|
|
(2,638 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
218,471 |
|
|
|
156,637 |
|
|
|
61,834 |
|
|
|
|
|
|
|
|
|
|
|
Total for pipelines and terminal assets (bpd) |
|
|
581,763 |
|
|
|
495,385 |
|
|
|
86,378 |
|
|
|
|
|
|
|
|
|
|
|
- 51 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended |
|
|
|
|
|
|
December 31, |
|
|
Change from |
|
|
|
2009 |
|
|
2008 |
|
|
2008 |
|
|
|
(In thousands, except per unit data) |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
$ |
43,206 |
|
|
$ |
40,446 |
|
|
$ |
2,760 |
|
Affiliates intermediate pipelines |
|
|
16,362 |
|
|
|
11,917 |
|
|
|
4,445 |
|
Affiliates crude pipelines |
|
|
29,266 |
|
|
|
22,380 |
|
|
|
6,886 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
88,834 |
|
|
|
74,743 |
|
|
|
14,091 |
|
Third parties refined product pipelines |
|
|
37,930 |
|
|
|
19,314 |
|
|
|
18,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
126,764 |
|
|
|
94,057 |
|
|
|
32,707 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
12,561 |
|
|
|
10,297 |
|
|
|
2,264 |
|
Third parties |
|
|
7,236 |
|
|
|
4,468 |
|
|
|
2,768 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,797 |
|
|
|
14,765 |
|
|
|
5,032 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
146,561 |
|
|
|
108,822 |
|
|
|
37,739 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
44,003 |
|
|
|
38,920 |
|
|
|
5,083 |
|
Depreciation and amortization |
|
|
26,714 |
|
|
|
21,937 |
|
|
|
4,777 |
|
General and administrative |
|
|
7,586 |
|
|
|
6,380 |
|
|
|
1,206 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
78,303 |
|
|
|
67,237 |
|
|
|
11,066 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
68,258 |
|
|
|
41,585 |
|
|
|
26,673 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of SLC Pipeline |
|
|
1,919 |
|
|
|
|
|
|
|
1,919 |
|
SLC Pipeline acquisition costs |
|
|
(2,500 |
) |
|
|
|
|
|
|
(2,500 |
) |
Interest income |
|
|
11 |
|
|
|
118 |
|
|
|
(107 |
) |
Interest expense, including amortization |
|
|
(21,501 |
) |
|
|
(21,763 |
) |
|
|
262 |
|
Gain on sale of assets |
|
|
|
|
|
|
36 |
|
|
|
(36 |
) |
Other |
|
|
67 |
|
|
|
990 |
|
|
|
(923 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,004 |
) |
|
|
(20,619 |
) |
|
|
(1,385 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes |
|
|
46,254 |
|
|
|
20,966 |
|
|
|
25,288 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
(20 |
) |
|
|
(270 |
) |
|
|
250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
46,234 |
|
|
|
20,696 |
|
|
|
25,538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of noncontrolling interest of $1,579
and $1,278 for the years ended December 31, 2009 and 2008, respectively |
|
|
5,301 |
|
|
|
4,671 |
|
|
|
630 |
|
Gain on sale of interest in Rio Grande |
|
|
14,479 |
|
|
|
|
|
|
|
14,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations |
|
|
19,780 |
|
|
|
4,671 |
|
|
|
15,109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
66,014 |
|
|
|
25,367 |
|
|
|
40,647 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less general partner interest in net income, including incentive distributions(2) |
|
|
7,947 |
|
|
|
3,913 |
|
|
|
4,034 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
58,067 |
|
|
$ |
21,454 |
|
|
$ |
36,613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners earnings per unit basic and diluted(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
2.12 |
|
|
$ |
1.04 |
|
|
$ |
1.08 |
|
Income from discontinued operations |
|
|
0.28 |
|
|
|
0.28 |
|
|
|
|
|
Gain on sale of discontinued operations |
|
|
0.78 |
|
|
|
|
|
|
|
0.78 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
3.18 |
|
|
$ |
1.32 |
|
|
$ |
1.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partners units outstanding |
|
|
18,268 |
|
|
|
16,291 |
|
|
|
1,977 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(3) |
|
$ |
100,707 |
|
|
$ |
70,195 |
|
|
$ |
30,512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow(4) |
|
$ |
72,213 |
|
|
$ |
60,365 |
|
|
$ |
11,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes from continuing operations (bpd)(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
|
88,001 |
|
|
|
83,203 |
|
|
|
4,798 |
|
Affiliates intermediate pipelines |
|
|
69,794 |
|
|
|
58,855 |
|
|
|
10,939 |
|
Affiliates crude pipelines |
|
|
137,244 |
|
|
|
111,426 |
|
|
|
25,818 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
295,039 |
|
|
|
253,484 |
|
|
|
41,555 |
|
Third parties refined product pipelines |
|
|
43,709 |
|
|
|
22,756 |
|
|
|
20,953 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
338,748 |
|
|
|
276,240 |
|
|
|
62,508 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
114,431 |
|
|
|
109,539 |
|
|
|
4,892 |
|
Third parties |
|
|
42,206 |
|
|
|
32,737 |
|
|
|
9,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
156,637 |
|
|
|
142,276 |
|
|
|
14,361 |
|
|
|
|
|
|
|
|
|
|
|
Total for pipelines and terminal assets (bpd) |
|
|
495,385 |
|
|
|
418,516 |
|
|
|
76,869 |
|
|
|
|
|
|
|
|
|
|
|
- 52 -
|
|
|
(1) |
|
On December 1, 2009, we sold our 70% interest in Rio Grande. Results of operations of Rio
Grande and the $14.5 million gain on the sale are presented in discontinued operations.
Pipeline volume information excludes volumes attributable to Rio Grande. |
|
(2) |
|
Net income is allocated between limited partners and the general partner interest in
accordance with the provisions of the partnership agreement. Net income allocated to the
general partner includes incentive distributions declared subsequent to quarter end. Net
income attributable to the limited partners is divided by the weighted average limited partner
units outstanding in computing the limited partners per unit interest in net income. |
|
(3) |
|
EBITDA is calculated as net income plus (i) interest expense, net of interest income, (ii)
state income tax and (iii) depreciation and amortization. EBITDA is not a calculation based
upon GAAP. However, the amounts included in the EBITDA calculation are derived from amounts
included in our consolidated financial statements, with the exception of EBITDA from
discontinued operations. EBITDA should not be considered as an alternative to net income or
operating income, as an indication of our operating performance or as an alternative to
operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to
similarly titled measures of other companies. EBITDA is presented here because it is a widely
used financial indicator used by investors and analysts to measure performance. EBITDA 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, Selected Financial Data. |
|
(4) |
|
Distributable cash flow is not a calculation based upon GAAP. However, the amounts included
in the calculation are derived from amounts separately presented in our consolidated financial
statements, with the exception of equity in excess cash flows over earnings of SLC Pipeline,
maintenance capital expenditures and distributable cash flow from discontinued operations.
Distributable cash flow should not be considered in isolation or as an alternative to net
income or operating income as an indication of our operating performance or as an alternative
to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily
comparable to similarly titled measures of other companies. Distributable cash flow is
presented here because it is a widely accepted financial indicator used by investors to
compare partnership performance. It is also used by management for internal analysis and for
our performance units. We believe that this measure provides investors an enhanced perspective
of the operating performance of our assets and the cash our business is generating. See our
calculation of distributable cash flow under Item 6, Selected Financial Data. |
Results of Operations Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
Summary
Income from continuing operations for the year ended December 31, 2010 was $58.9 million, a $12.6
million increase compared to the year ended December 31, 2009. This increase in overall earnings
was due principally to earnings attributable to our 2009 and March 2010 asset acquisitions and
overall increased shipments on our pipeline systems. These factors were partially offset by a
decrease in previously deferred revenue realized and increased operating costs and expenses and
interest expense.
Revenues for the year ended December 31, 2010 include the recognition of $8.4 million of prior
shortfalls billed to shippers in 2009 as they did not meet their minimum volume commitments in any
of the subsequent four quarters. Revenues of $10.4 million relating to deficiency payments
associated with certain guaranteed shipping contracts were deferred during the year ended December
31, 2010. Such deferred revenue will be recognized in earnings either as payment for shipments in
excess of guaranteed levels or in 2011 when shipping rights expire unused after a twelve-month
period.
- 53 -
Revenues
Total revenues from continuing operations for the year ended December 31, 2010 were $182.1 million,
a $35.5 million increase compared to the year ended December 31, 2009. This increase is due
principally to revenues attributable to our recent asset acquisitions and higher tariffs on
affiliate shipments, partially offset by a $7.3 million decrease in previously deferred revenue
realized. For 2010, overall pipeline shipments were up 7%, reflecting increased affiliate volumes
attributable to Hollys first quarter of 2009 Navajo refinery expansion, including volumes shipped
on our new 16-inch intermediate and Beeson pipelines, partially offset by a decrease in third-party
shipments. Additionally, prior year affiliate shipments reflect lower volumes as a result of
production downtime during a major maintenance turnaround of the Navajo refinery during the first
quarter of 2009. Overall terminal and loading rack volumes were also up in 2010, increasing 39%
over 2009 levels due principally to volumes transferred and stored at our Tulsa storage and rack
facilities.
Revenues from our refined product pipelines were $76.4 million, a decrease of $4.7 million compared
to the year ended December 31, 2009. This decrease was due principally to an $8.5 million decrease
in previously realized deferred revenue that was partially offset by an overall increase in refined
product pipeline shipments. Volumes shipped on our refined product pipeline system averaged 135
thousand barrels per day (mbpd) compared to 131.7 mbpd for the year ended December 31, 2009,
reflecting an increase in affiliate shipments, partially offset by a decline in third-party
shipments.
Revenues from our intermediate pipelines were $21 million, an increase of $4.6 million compared to
the year ended December 31, 2009. This increase was due principally to increased shipments on our
intermediate pipeline system combined with a $1.2 million increase in previously deferred revenue
realized. Volumes shipped on our intermediate product pipeline system increased to an average of
84.3 mbpd compared to 69.8 mbpd for 2009.
Revenues from our crude pipelines were $38.9 million, an increase of $9.7 million compared to the
year ended December 31, 2009. This increase was due principally to an $8.4 million year-over-year
increase in revenues attributable to our Roadrunner Pipeline agreement. Volumes shipped on our
crude pipeline system increased to an average of 144 mbpd compared to 137.2 mbpd for 2009.
Revenues from terminal, tankage and loading rack fees were $45.7 million, an increase of $25.9
million compared to the year ended December 31, 2009. This includes a $24.7 million year-over-year
increase in revenues attributable to volumes transferred and stored at our Tulsa storage and rack
facilities. Refined products terminalled in our facilities increased to an average of 218.5 mbpd
compared to 156.6 mbpd for 2009.
Operations Expense
Operations expense for the year ended December 31, 2010 increased by $8.9 million compared to the
year ended December 31, 2009. This increase was due principally to costs attributable to overall
higher throughput volumes, including those from our recent asset acquisitions, and higher
maintenance and payroll costs.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2010 increased by $4 million compared
to the year ended December 31, 2009. This increase is attributable to our 2009 and March 2010
asset acquisitions and capital projects. Additionally, effective January 1, 2010, we revised the
estimated useful lives of our terminal assets to 16 to 25 years resulting in a $3 million reduction
in depreciation expense for the year ended December 31, 2010.
- 54 -
General and Administrative
General and administrative costs for the year ended December 31, 2010 of $7.7 million was
relatively flat compared to $7.6 million for the year ended December 31, 2009.
Equity in Earnings of SLC Pipeline
Our equity in earnings of the SLC Pipeline was $2.4 million and $1.9 million for the years ended
December 31, 2010 and December 31, 2009, respectively.
SLC Pipeline Acquisition Costs
We incurred a $2.5 million finders fee in connection with the acquisition our SLC Pipeline joint
venture interest in March 2009. As a result of accounting requirements effective January 1, 2009,
we were required to expense rather than capitalize these direct acquisition costs.
Interest Expense
Interest expense for the year ended December 31, 2010 totaled $34 million, an increase of $12.5
million compared to the year ended December 31, 2009. This increase reflects interest on our 8.25%
senior notes and costs of $1.1 million from a partial settlement of an interest rate swap. For the
years ended December 31, 2010 and 2009, fair value adjustments to our interest rate swaps resulted
in $1.5 million and $0.2 million, respectively, in non-cash interest expense. Excluding the
effects of these fair value adjustments, our aggregate effective interest rate was 6.8% for the
year ended December 31, 2010 compared to 5.3% for 2009.
State Income Tax
We recorded state income taxes of $296,000 and $20,000 for the years ended December 31, 2010 and
2009, respectively, which are solely attributable to the Texas margin tax. State income taxes for
the year ended December 31, 2009 are presented net of a $167,000 tax refund resulting from
over-estimates of prior year margin taxes.
Discontinued Operations
We sold our interest in Rio Grande on December 1, 2009. Income from discontinued operations for the
year ended December 31, 2009 includes a gain from the sale of our 70% interest in Rio Grande of
$14.5 million. Rio Grande operations generated earnings of $6.9 million for the year ended
December 31, 2009, presented net of earnings attributable to noncontrolling interest holders of
$1.6 million.
Results of Operations Year Ended December 31, 2009 Compared with Year Ended December 31, 2008
Summary
Income from continuing operations for the year ended December 31, 2009 was $46.2 million, a $25.5
million increase compared to the year ended December 31, 2008. This increase in overall earnings
was due principally to overall increased shipments on our pipeline systems, earnings attributable
to our 2009 asset acquisitions, the effect of the annual tariff increase on affiliate pipeline
shipments and an increase in previously deferred revenue realized.
Revenues for the year ended December 31, 2009 include the recognition of $15.7 million of prior
shortfalls billed to shippers in 2008 as they did not meet their minimum volume commitments in any
of the subsequent four quarters. Revenues of $8.4 million relating to deficiency payments
associated with certain guaranteed shipping contracts was deferred during the year ended December
31, 2009 and was recognized in 2010 when shipping rights expired unused after a twelve-month
period.
- 55 -
Revenues
Total revenues from continuing operations for the year ended December 31, 2009 were $146.6 million,
a $37.7 million increase compared to the year ended December 31, 2008. This increase was due
principally to overall increased shipments on our pipeline systems, increased revenues attributable
to our crude pipeline assets acquired in the first quarter of 2008, the effect of annual tariff
increases on affiliate pipeline shipments, an increase in previously deferred revenue realized and
revenues attributable to our Tulsa facilities acquired in 2009. Increased volumes attributable
to Hollys Navajo refinery expansion in the first quarter of 2009, including volumes shipped on our
new 16-inch intermediate and Beeson pipelines acquired in 2009 contributed to an increase in
affiliate pipeline shipments. Affiliate shipments for the year ended December 31, 2009 were also
impacted by the effects of reduced production during Hollys planned maintenance turnaround of its
Navajo refinery in the first quarter of 2009. Additionally, third-party refined product shipments
were up for 2009 compared to 2008, which had been down as a result of limited production resulting
from an explosion and fire at Alons Big Spring refinery in the first quarter of 2008.
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 2008, Alon reopened its Big Spring refinery
and resumed production at approximately one-half of refining capacity until production was restored
in late September and later increased to full capacity during the fourth quarter of 2008. 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.
Revenues from our refined product pipelines were $81.1 million, an increase of $21.4 million
compared to the year ended December 31, 2008. This increase was due principally to increased
shipments on our refined product pipeline system, the effect of the annual tariff increase on
affiliate refined product shipments and a $10.7 million increase in previously deferred revenue
realized. Volumes shipped on our refined product pipeline system increased to an average of 131.7
mbpd compared to 106 mbpd for 2008.
Revenues from our intermediate pipelines were $16.4 million, an increase of $4.4 million compared
to the year ended December 31, 2008. This increase was due principally to increased shipments on
our intermediate pipeline system including volumes shipped on our 16-inch pipeline acquired in
2009, the effect of the annual tariff increase on intermediate pipeline shipments and a $1.1
million increase in previously deferred revenue realized. Volumes shipped on our intermediate
product pipeline system increased to an average of 69.8 mbpd compared to 58.9 mbpd for 2008.
Revenues from our crude pipelines were $29.3 million, an increase of $6.9 million compared to the
year ended December 31, 2008. This increase was due principally to the realization of revenues
from crude oil shipments for a full twelve-month period during the year ended December 31, 2009
compared to ten months of shipments during 2008 due to the commencement of operations on March 1,
2008, increased shipments on our crude pipeline system and the effect of the annual tariff
increase. Additionally, this increase includes $0.8 million in revenues attributable to our
Roadrunner Pipeline transportation agreement with Holly. Volumes shipped on our crude pipeline
system increased to an average of 137.2 mbpd compared to 111.4 mbpd for 2008.
Revenues from terminal, tankage and loading rack fees were $19.8 million, an increase of $5 million
compared to the year ended December 31, 2008. This increase includes $2.5 million in revenues
attributable to volumes transferred via our Tulsa facilities acquired in 2009. Refined products
terminalled in our facilities increased to an average of 156.6 mbpd compared to 142.3 mbpd for
2008.
Operations Expense
Operations expense for the year ended December 31, 2009 increased by $5.1 million compared to the
year ended December 31, 2008. This increase was due principally to costs attributable to higher
throughput volumes, including those from our 2009 asset acquisitions, and higher maintenance and
payroll expense.
- 56 -
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2009 increased by $4.8 million
compared to the year ended December 31, 2008. This increase was attributable to our 2009 and 2008
asset acquisitions and capital projects.
General and Administrative
General and administrative costs for the year ended December 31, 2009 increased by $1.2 million
compared to the year ended December 31, 2008, due principally to increased professional fees
related to our 2009 asset acquisitions.
Equity in Earnings of SLC Pipeline
The SLC Pipeline commenced pipeline operations effective March 2009. Our equity in earnings of the
SLC Pipeline was $1.9 million for the year ended December 31, 2009.
SLC Pipeline Acquisition Costs
We incurred a $2.5 million finders fee in connection with the acquisition our SLC Pipeline joint
venture interest in March 2009.
Interest Expense
Interest expense for the year ended December 31, 2009 totaled $21.5 million, a decrease of $0.3
million compared to the year ended December 31, 2008. For the years ended December 31, 2009 and
2008, fair value adjustments to our interest rate swaps resulted in $0.2 million and $2.3 million,
respectively, in non-cash interest expense. Excluding the effects of these fair value adjustments,
our aggregate effective interest rate was 5.3% for the year ended December 31, 2009 compared to
5.4% for 2008.
State Income Tax
We recorded state income taxes of $20,000 and $270,000 for the years ended December 31, 2009 and
2008, respectively, which are solely attributable to the Texas margin tax. State income taxes for
the year ended December 31, 2009 are presented net of a $167,000 tax refund resulting from
over-estimates of prior year margin taxes.
Discontinued Operations
Income from discontinued operations for the year ended December 31, 2009 includes a gain from the
sale of our 70% interest in Rio Grande of $14.5 million in December 2009. Rio Grande operations
generated earnings of $6.9 million and $5.9 million for the years ended December 31, 2009 and 2008,
respectively. Rio Grande earnings for the years ended December 31, 2009 and 2008 are presented net
of earnings attributable to noncontrolling interest holders of $1.6 million and $1.3 million,
respectively.
LIQUIDITY AND CAPITAL RESOURCES
Overview
At December 31, 2010, we had a $300 million senior secured revolving credit agreement expiring in
August 2011 (the Credit Agreement). During the year ended December 31, 2010, we received
advances totaling $66 million and repaid $113 million, resulting in the net repayment of $47
million in advances under the Credit Agreement and an outstanding balance of $159 million at
December 31, 2010. These advances were used to finance acquisitions and capital projects. As of
December 31, 2010, we had no working capital borrowings.
- 57 -
On February 14, 2011 we amended the Credit Agreement, slightly reducing the size from $300 million
to $275 million. The size was reduced based on managements review of past and forecasted
utilization of the facility. The Amended Credit Agreement expires in February 2016 and is
available to fund capital expenditures, investments, acquisitions, distribution payments and
working capital and for general partnership purposes. The Amended Credit Agreement is available to
fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders up to
a $30 million sub-limit.
If any particular lender under the Amended Credit Agreement could not honor its commitment, we
believe the unused capacity that would be available from the remaining lenders would be sufficient
to meet our borrowing needs. Additionally, we review publicly available information on the lenders
in order to monitor their financial stability and assess their ongoing ability to honor their
commitments under the Amended Credit Agreement. We do not expect to experience any difficulty in
the lenders ability to honor their respective commitments, and if it were to become necessary, we
believe there would be alternative lenders or options available.
In March 2010, we issued $150 million in aggregate principal amount of 8.25% senior notes maturing
March 15, 2018 (the 8.25% Senior Notes). A portion of the $147.5 million in net proceeds
received was used to fund our $93 million purchase of the Tulsa and Lovington storage assets from
Holly on March 31, 2010. Additionally, we used a portion to repay $42 million in outstanding
Credit Agreement borrowings, with the remaining proceeds available for general partnership
purposes, including working capital and capital expenditures.
Our 6.25% senior notes having an aggregate principal amount outstanding of $185 million mature
March 1, 2015 and are registered with the SEC (the 6.25% Senior Notes). The 6.25% Senior Notes
and 8.25% Senior Notes (collectively, the Senior Notes) are unsecured and have certain
restrictive covenants, which we are subject to and currently in compliance with, including
limitations on our ability to incur additional indebtedness, make investments, sell assets, incur
certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers.
At any time when the Senior Notes are rated investment grade by both 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.
Under our registration statement filed with the SEC using a shelf registration process, we
currently have the ability to raise $860 million through security offerings, through one or more
prospectus supplements that would describe, among other things, the specific amounts, prices and
terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of
securities would be used for general business purposes, which may include, among other things,
funding acquisitions of assets or businesses, working capital, capital expenditures, investments in
subsidiaries, the retirement of existing debt and/or the repurchase of common units or other
securities.
We believe our current cash balances, future internally generated funds and funds available under
the Amended Credit Agreement will provide sufficient resources to meet our working capital
liquidity needs for the foreseeable future.
In February, May, August and November 2010, we paid regular quarterly cash distributions of $0.805,
$0.815, $0.825 and $0.835, respectively, on all units, an aggregate amount of $84.4 million.
Included in these distributions was $10.3 million paid to the general partner as incentive
distributions.
Cash flows from continuing and discontinued operations have been combined for presentation purposes
in the Consolidated Statements of Cash Flows. For the years ended December 31, 2009 and 2008, net
cash flows from our discontinued Rio Grande operations were $37.6 million and $3.5 million,
respectively. Net cash flows from discontinued operations for 2009 include $35 million in proceeds
received upon the sale of our Rio Grande interest.
- 58 -
Cash and cash equivalents decreased by $2.1 million during the year ended December 31, 2010. The
combined cash flows used for investing and financing activities of $60.6 million and $44.6 million,
respectively, exceeded cash flows provided by operating activities of $103.2 million. Working
capital decreased by $12.2 million to $(7.8) million during the year ended December 31, 2010.
Cash Flows Operating Activities
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
Cash flows from operating activities increased by $35 million from $68.2 million for the year ended
December 31, 2009 to $103.2 million for the year ended December 31, 2010. This increase is due
principally to $38 million in additional cash collections from our major customers, resulting from
increased revenues, partially offset by year-over-year changes in payments attributable to costs of
increased operations and interest.
Our major shippers are obligated to make deficiency payments to us if they do not meet their
minimum volume shipping obligations. Under certain agreements with these shippers, they have the
right to recapture these amounts if future volumes exceed minimum levels. For the year ended
December 31, 2010, we received cash payments of $11.7 million under these commitments. We billed
$8.4 million during the year ended December 31, 2009 related to shortfalls that subsequently
expired without recapture and were recognized as revenue during the year ended December 31, 2010.
Another $1.4 million is included in our accounts receivable at December 31, 2010 related to
shortfalls that occurred in the fourth quarter of 2010.
Year Ended December 31, 2009 Compared with Year Ended December 31, 2008
Cash flows from operating activities increased by $4.5 million from $63.7 million for the year
ended December 31, 2008 to $68.2 million for the year ended December 31, 2009. This increase is
due principally to $12.4 million in additional cash collections from our major customers, resulting
principally from increased revenues, partially offset by year-over-year changes in payments
attributable to increased operations.
For the year ended December 31, 2009, we received cash payments of $8.6 million under minimum
volume shipping commitments. We billed $15.7 million during the year ended December 31, 2008
related to shortfalls that subsequently expired without recapture and was recognized as revenue
during the year ended December 31, 2009. Another $2.7 million is included in our accounts
receivable at December 31, 2009 related to shortfalls that occurred in the fourth quarter of 2009.
Cash Flows Investing Activities
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
Cash flows used for investing activities decreased by $86.8 million from $147.4 million for the
year ended December 31, 2009 to $60.6 million for the year ended December 31, 2010. During the
year ended December 31, 2010, we acquired storage assets from Holly for $35.5 million and invested
$25.1 million in additions to properties and equipment. During the year ended December 31, 2009,
we paid $95.1 million with respect to our asset acquisitions from Holly, consisting of a 16-inch
intermediate pipeline, loading rack facilities in Tulsa, Oklahoma and the Roadrunner and Beeson
Pipelines. We also paid $25.7 million in cash upon our purchase of the logistics and storage
assets from Sinclair and purchased our 25% joint venture interest in the SLC Pipeline for $25.5
million. Additionally, we invested $33 million in additions to properties and equipment for the
year ended December 31, 2009. These additions relate principally to the expansion of our pipeline
system between Artesia, New Mexico and El Paso, Texas, the South System. On December 1, 2009, we
sold our 70% interest in Rio Grande for $35 million. Proceeds received are presented net of Rio
Grandes cash balance of $3.1 million
- 59 -
Year Ended December 31, 2009 Compared with Year Ended December 31, 2008
Cash flows used for investing activities decreased by $65.9 million from $213.3 million for the
year ended December 31, 2008 to $147.4 million for the year ended December 31, 2009. During the
year ended December 31, 2009, we paid $95.1 million with respect to our asset acquisitions from
Holly, consisting of a 16-inch intermediate pipeline, loading rack facilities in Tulsa, Oklahoma
and the Roadrunner and
Beeson Pipelines. We also paid $25.7 million in cash upon our purchase of the logistics and
storage assets from Sinclair and purchased our 25% joint venture interest in the SLC Pipeline for
$25.5 million. Additionally, we invested $33 million in additions to properties and equipment for
the year ended December 31, 2009 compared to $42.3 million for the year ended December 31, 2008.
These additions relate principally to the expansion of our pipeline system between Artesia, New
Mexico and El Paso, Texas, the South System. On December 1, 2009, we sold our 70% interest in Rio
Grande for $35 million. Proceeds received are presented net of Rio Grandes cash balance of $3.1
million. During the year ended December 31, 2008, we paid $171 million in connection with our
purchase of the crude pipelines and tankage assets from Holly in February 2008.
Cash Flows Financing Activities
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
Cash flows used for financing activities were $44.6 million for the year ended December 31, 2010, a
decrease of $121 million compared to cash flows provided by financing activities of $76.4 million
for the year ended December 31, 2009. During the year ended December 31, 2010, we received $66
million and repaid $113 million in advances under the Credit Agreement. Also, we received $147.5
million in net proceeds and incurred $0.5 million in financing costs upon the issuance of the 8.25%
Senior Notes. During the year ended December 31, 2010, we paid $84.4 million in regular quarterly
cash distributions to our general and limited partners, paid $57.6 million in excess of Hollys
transferred basis in the storage assets acquired in March 2010 and paid $2.7 million for the
purchase of common units for recipients of our restricted unit incentive grants. During the year
ended December 31, 2009, we received $239 million and repaid $233 million in advances under the
Credit Agreement. Also, we received $133.3 million in proceeds and incurred $0.3 million in costs
with respect to our November and May 2009 equity offerings. During the year ended December 31,
2009, we paid $61.2 million in regular quarterly cash distributions to our general and limited
partners, paid $3.1 million in excess of Hollys transferred basis in the assets acquired from
Holly in 2009 and paid $1.5 million in distributions to noncontrolling interest holders in Rio
Grande. Additionally during 2009, we received $3.8 million in capital contributions from our
general partner and paid $0.6 million for the purchase of common units for recipients of our
restricted unit incentive grants.
Year Ended December 31, 2009 Compared with Year Ended December 31, 2008
Cash flows provided by financing activities decreased by $68.2 million from $144.6 million for the
year ended December 31, 2008 to $76.4 million for the ended December 31, 2009. During the year
ended December 31, 2009, we received $239 million and repaid $233 million in advances under the
Credit Agreement. Also, we received $133.3 million in proceeds and incurred $0.3 million in costs
with respect to our November and May 2009 equity offerings. During the year ended December 31,
2009, we paid $61.2 million in regular quarterly cash distributions to our general and limited
partners, paid $3.1 million in excess of Hollys transferred basis in the assets acquired from
Holly in 2009 and paid $1.5 million in distributions to noncontrolling interest holders in Rio
Grande. Additionally during 2009, we received $3.8 million in capital contributions from our
general partner and paid $0.6 million for the purchase of common units for recipients of our
restricted unit incentive grants. During the year ended December 31, 2008, we received net
advances of $200 million under the Credit Agreement of which $171 million were used to finance the
cash portion of the consideration paid to acquire the crude pipelines and tankage assets. During
the year ended December 31, 2008, we paid $52.4 million in distributions on all units including the
general partner interest and paid $1.8 million in distributions to noncontrolling interest holders
in Rio Grande. Additionally in 2008, we paid $0.8 million for the purchase of our common units for
restricted unit grants and paid $0.7 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.
- 60 -
Each year the HLS board of directors approves our annual capital budget, which specifies capital
projects that our management is authorized to undertake. Additionally, at times when conditions
warrant or as new opportunities arise, special projects may be approved. The funds allocated for a
particular capital project may be expended over a period in excess of a year, depending on the time
required to complete the project. Therefore, our planned capital expenditures for a given year
consist of expenditures approved for capital projects included in the current years capital budget
as well as, in certain cases, expenditures approved for capital projects in capital budgets for
prior years. The 2011 capital budget is comprised of $5.8 million for maintenance capital
expenditures and $20.1 million for expansion capital expenditures.
We are currently constructing five interconnecting pipelines between Hollys Tulsa east and west
refining facilities. The project is expected to cost approximately $28 million with completion in
the second quarter of 2011. We are currently negotiating terms for a long-term agreement with
Holly to transfer intermediate products via these pipelines that will commence upon completion of
the project. In the event that we are unable to obtain such an agreement, Holly will reimburse us
for the cost of the pipelines.
We have an option agreement with Holly, granting us an option to purchase Hollys 75% equity
interest in the UNEV Pipeline, a joint venture pipeline currently under construction that will be
capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada.
Under this agreement, we have an option to purchase Hollys equity interest in the UNEV Pipeline,
effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase
price equal to 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 current total cost of the pipeline project including terminals is expected to be
approximately $325 million. This includes the construction of ethanol blending and storage
facilities at the Cedar City terminal. The pipeline is in the final construction phase and is
expected to be mechanically complete in the second quarter of 2011.
We expect that our currently planned sustaining and maintenance capital expenditures as well as
expenditures for acquisitions and capital development projects such as the UNEV Pipeline described
above, will be funded with existing cash generated by operations, the sale of additional limited
partner common units, the issuance of debt securities and advances under our Amended Credit
Agreement, or a combination thereof. With volatility and uncertainty at times in the credit and
equity markets, there may be limits on our ability to issue new debt or equity financing.
Additionally, due to pricing movements in the debt and equity markets, we may not be able to issue
new debt and equity securities at acceptable pricing. Without additional capital beyond amounts
available under the Amended Credit Agreement, our ability to fund some of these capital projects
may be limited, especially the UNEV Pipeline. We are not obligated to purchase the UNEV Pipeline
nor are we subject to any fees or penalties if HLS board of directors decides not to proceed with
this opportunity.
Credit Agreement
Our $275 million Amended Credit Agreement expires in February 2016; provided that the Amended
Credit Agreement will expire on September 1, 2014 in the event that, on or prior to such date, the
6.25% Senior Notes have not been repurchased, refinanced, extended or repaid. The Amended Credit
Agreement is available to fund capital expenditures, investments, acquisitions, distribution
payments and working capital and for general partnership purposes.
Our obligations under the Amended Credit Agreement are collateralized by substantially all of our
assets. Indebtedness under the Amended Credit Agreement is recourse to HEP Logistics Holdings,
L.P., our general partner, and guaranteed by our material, wholly-owned subsidiaries. Any recourse
to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its
investment in us, are not significant.
We may prepay all loans at any time without penalty, except for payment of certain breakage and
related costs.
- 61 -
Indebtedness under the Amended Credit Agreement bears interest, at our option, at either (a) the
reference rate as announced by the administrative agent plus an applicable margin (ranging from
1.00% to 2.00%) or (b) at a rate equal to the London Interbank Offered Rate (LIBOR) plus an
applicable margin (ranging from 2.00% to 3.00%). In each case, the applicable margin is based upon
the ratio of our funded debt (as defined in the Amended Credit Agreement) to EBITDA (earnings
before interest, taxes, depreciation and amortization, as defined in the Amended Credit Agreement).
We incur a commitment fee on the unused portion of the Amended Credit Agreement at a rate ranging
from 0.375% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently
completed fiscal quarters.
The Amended Credit Agreement imposes certain requirements on us including: a prohibition against
distribution to unitholders if, before or after the distribution, a potential default or an event
of default as defined in the agreement would occur; limitations on our ability to incur debt, make
loans, acquire other companies, change the nature of our business, enter a merger or consolidation,
or sell assets; and covenants that require maintenance of a specified EBITDA to interest expense
ratio, total debt to EBITDA ratio and senior debt to EBITDA ratio. If an event of default exists
under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise
other rights and remedies.
Senior Notes
The 6.25% Senior Notes and 8.25% Senior Notes 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 its assets, which other than its investment in us,
are not significant.
Our purchase and contribution agreements with Holly with respect to the intermediate pipelines and
the crude pipelines and tankage assets restrict us from selling pipelines and terminals acquired
from Holly and from prepaying borrowings and long-term debt to outstanding balances below $35
million and $171 million prior to 2015 and 2018, respectively, in each case subject to certain
limited exceptions.
Long-term Debt
The carrying amounts of our long-term debt are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
Credit Agreement |
|
$ |
159,000 |
|
|
$ |
206,000 |
|
|
|
|
|
|
|
|
|
|
6.25% Senior Notes |
|
|
|
|
|
|
|
|
Principal |
|
|
185,000 |
|
|
|
185,000 |
|
Unamortized discount |
|
|
(1,584 |
) |
|
|
(1,964 |
) |
Unamortized premium dedesignated fair value hedge |
|
|
1,444 |
|
|
|
1,791 |
|
|
|
|
|
|
|
|
|
|
|
184,860 |
|
|
|
184,827 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.25% Senior Notes |
|
|
|
|
|
|
|
|
Principal |
|
|
150,000 |
|
|
|
|
|
Unamortized discount |
|
|
(2,212 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
147,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
491,648 |
|
|
$ |
390,827 |
|
|
|
|
|
|
|
|
- 62 -
Our interest rate swap contracts are discussed under Risk Management.
Long-term Contractual Obligations
The following table presents our long-term contractual obligations as of December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
|
|
|
|
|
|
Less than |
|
|
|
|
|
|
|
|
|
|
Over 5 |
|
|
|
Total |
|
|
1 Year |
|
|
1-3 Years |
|
|
3-5 Years |
|
|
Years |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt principal |
|
$ |
494,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
185,000 |
|
|
$ |
309,000 |
|
Long-term debt interest |
|
|
161,228 |
|
|
|
27,134 |
|
|
|
54,269 |
|
|
|
48,488 |
|
|
|
31,337 |
|
Pipeline operating lease |
|
|
40,619 |
|
|
|
6,249 |
|
|
|
12,498 |
|
|
|
12,498 |
|
|
|
9,374 |
|
Right-of-way leases |
|
|
1,805 |
|
|
|
296 |
|
|
|
456 |
|
|
|
341 |
|
|
|
712 |
|
Other |
|
|
9,814 |
|
|
|
1,135 |
|
|
|
2,120 |
|
|
|
2,120 |
|
|
|
4,439 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
707,466 |
|
|
$ |
34,814 |
|
|
$ |
69,343 |
|
|
$ |
248,447 |
|
|
$ |
354,862 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our long-term debt consists of $185 million, $150 million and $159 million in outstanding
principal under the 6.25% Senior Notes, the 8.25% Senior Notes and the Credit Agreement,
respectively. The Credit Agreement was amended on February 14, 2011; the Amended Credit Agreement
expires in 2016.
The pipeline operating lease amounts above 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 above include only obligations under the remaining non-cancelable terms of these
agreements at December 31, 2010. 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.
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, 2010, 2009 and 2008.
A substantial majority of our revenues are generated under long-term contracts that provide for
increases in our rates and minimum revenue guarantees annually for increases in the PPI.
Historically, the PPI has increased an average of 3% annually over the past 5 calendar years. This
is no indication of PPI increases to be realized in the future. Furthermore, certain of our
long-term contracts have provisions that limit the level of annual PPI percentage rate increases.
Environmental Matters
Our operation of pipelines, terminals, and associated facilities in connection with the
transportation and storage of refined products and crude oil is subject to stringent and complex
federal, state, and local laws and regulations governing the discharge of materials into the
environment, or otherwise relating to the protection of the environment. As with the industry
generally, compliance with existing and anticipated laws and regulations increases our overall cost
of business, including our capital costs to construct, maintain, and upgrade equipment and
facilities. While these laws and regulations affect our maintenance capital expenditures and net
income, we believe that they do not affect our competitive position in that the operations of our
competitors are similarly affected. We believe that our operations are in substantial compliance
with applicable environmental laws and regulations. However, these laws and regulations, and the
interpretation or enforcement thereof, are subject to frequent change by regulatory authorities,
and we are unable to predict the ongoing cost to us of complying with these laws and regulations or
the future impact of these laws and regulations on our operations. Violation of environmental
laws, regulations, and permits can result in the imposition of significant administrative, civil
and criminal penalties, injunctions, and construction bans or delays. A discharge of hydrocarbons
or hazardous
substances into the environment could, to the extent the event is not insured, subject us to
substantial expense, including both the cost to comply with applicable laws and regulations and
claims made by employees, neighboring landowners and other third parties for personal injury and
property damage.
- 63 -
Under the Omnibus Agreement, Holly agreed to indemnify us up to certain aggregate amounts for any
environmental noncompliance and remediation liabilities associated with assets transferred to us
and occurring or existing prior to the date of such transfers. The transfers that are covered by
the agreement include the refined product pipelines, terminals and tanks transferred by Hollys
subsidiaries in connection with our initial public offering in July 2004, the intermediate
pipelines acquired in July 2005, the crude pipelines and tankage assets acquired in 2008, and the
asphalt loading rack facility acquired in March 2010. The Omnibus Agreement provides environmental
indemnification of up to $15 million for the assets transferred to us, other than the crude
pipelines and tankage assets, plus an additional $2.5 million for the intermediate pipelines
acquired in July 2005. Except as described below, Hollys indemnification obligations described
above will remain in effect for an asset for ten years following the date it is transferred to us.
The Omnibus Agreement also provides an additional $7.5 million of indemnification through 2023 for
environmental noncompliance and remediation liabilities specific to the crude pipelines and tankage
assets. Hollys indemnification obligations described above do not apply to (i) the Tulsa west
loading racks acquired in August 2009, (ii) the 16-inch intermediate pipeline acquired in June
2009, (iii) the Roadrunner Pipeline, (iv) the Beeson Pipeline, (v) the logistics and storage assets
acquired from Sinclair in December 2009, or (vi) the Tulsa east storage tanks and loading racks
acquired in March 2010.
Under provisions of the Holly ETA and Holly PTTA, Holly will indemnify us for environmental
liabilities arising from our pre-ownership operations of the Tulsa west loading rack facilities
acquired from Holly in August 2009, the Tulsa logistics and storage assets acquired from Sinclair
in December 2009 and the Tulsa east storage tanks and loading racks acquired from Holly in March
2010. Additionally, Holly agreed to indemnify us for any liabilities arising from Hollys
operation of the loading racks under the Holly ETA.
We have an environmental agreement with Alon with respect to pre-closing environmental costs and
liabilities relating to the pipelines and terminals acquired from Alon in 2005, under which Alon
will indemnify us through 2015, subject to a $100,000 deductible and a $20 million maximum
liability cap.
There are environmental remediation projects that are currently in progress that relate to certain
assets acquired from Holly. Certain of these projects were underway prior to our purchase and
represent liabilities of Holly Corporation as the obligation for future remediation activities was
retained by Holly. At December 31, 2010, we have an accrual of $0.3 million that relates to
environmental clean-up projects for which we have assumed liability. The remaining projects,
including assessment and monitoring activities, are covered under the Holly environmental
indemnification discussed above and represent liabilities of Holly Corporation.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition and results of operations are based upon our
consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States. The preparation of these financial statements
requires us to make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as
of the date of the financial statements. Actual results may differ from these estimates under
different assumptions or conditions. We consider the following policies to be the most critical to
understanding the judgments that are involved and the uncertainties that could impact our results
of operations, financial condition and cash flows.
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.
- 64 -
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, and actual results
could differ from those estimates.
We have evaluated our transportation agreements for impairment as of December 31, 2010 and
determined that projected cash flows to be received under these agreements substantially exceed our
carrying balances. Furthermore, there were no impairments of our long-lived assets during the
years ended December 31, 2010, 2009 and 2008.
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.
RISK MANAGEMENT
We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.
As of December 31, 2010, we have an interest rate swap that hedges our exposure to the cash flow
risk caused by the effects of LIBOR changes on a $155 million Credit Agreement advance. This
interest rate swap effectively converts $155 million of our LIBOR based debt to fixed rate debt
having an interest rate of 3.74% plus an applicable margin of 1.75%, which equaled an effective
interest rate of 5.49% as of December 31, 2010. This swap contract matures in February 2013.
- 65 -
We have designated this interest rate swap as a cash flow hedge. Based on our assessment of
effectiveness using the change in variable cash flows method, we have determined that this interest
rate
swap is effective in offsetting the variability in interest payments on $155 million of our
variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash
flow hedge on a quarterly basis to its fair value with the offsetting fair value adjustment to
accumulated other comprehensive loss. Also on a quarterly basis, we measure hedge effectiveness by
comparing the present value of the cumulative change in the expected future interest to be paid or
received on the variable leg of our swap against the expected future interest payments on $155
million of our variable rate debt. Any ineffectiveness is reclassified from accumulated other
comprehensive loss to interest expense. To date, we have had no ineffectiveness on our cash flow
hedge.
Additional information on our interest rate swaps are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
|
|
|
|
Location of Offsetting |
|
|
Offsetting |
|
Derivative Instrument |
|
Location |
|
|
Fair Value |
|
|
Balance |
|
|
Amount |
|
|
|
(In thousands) |
|
December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swap designated as cash flow hedging instrument: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable-to-fixed interest rate swap contract
($155 million of LIBOR based debt interest) |
|
Other long-term liabilities |
|
$ |
10,026 |
|
|
Accumulated other comprehensive loss |
|
$ |
10,026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swap designated as cash flow hedging instrument: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable-to-fixed interest rate swap contract
($171 million of LIBOR based debt interest) |
|
Other long-term liabilities |
|
$ |
9,141 |
|
|
Accumulated other comprehensive loss |
|
$ |
9,141 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-variable interest rate swap contract
($60 million of 6.25% Senior Notes interest) |
|
Other assets |
|
$ |
2,294 |
|
|
Long-term debt |
|
$ |
1,791 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity |
|
|
503 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,294 |
|
|
|
|
|
|
$ |
2,294 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable-to-fixed interest rate swap contract
($60 million of 6.25% Senior Notes interest) |
|
Other long-term liabilities |
|
$ |
2,555 |
|
|
Equity |
|
$ |
2,555 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents unamortized balance of deferred hedge premium. |
|
(2) |
|
Represents prior year charges to interest expense. |
In May 2010, we repaid $16 million of our Credit Agreement debt and also settled a
corresponding portion of our interest rate swap agreement having a notional amount of $16 million
for $1.1 million. Upon payment, we reduced our swap liability and reclassified a $1.1 million
charge from accumulated other comprehensive loss to interest expense, representing the application
of hedge accounting prior to settlement.
In the first quarter of 2010, we settled two interest rate swaps. We had an interest rate swap
contract that effectively converted interest expense associated with $60 million of our 6.25%
Senior Notes from fixed to variable rate debt (Variable Rate Swap). We had an additional
interest rate swap contract that effectively unwound the effects of the Variable Rate Swap,
converting $60 million of the previously hedged long-term debt back to fixed rate debt (Fixed Rate
Swap), effectively fixing interest at a 4.75% rate. Upon settlement of the Variable Rate and
Fixed Rate Swaps, we received $1.9 million and paid $3.6 million, respectively.
For the years ended December 31, 2010, 2009 and 2008, we recognized $1.5 million, $0.2 million and
$2.3 million, respectively, in non-cash charges to interest expense as a result of fair value
adjustments to our interest rate swaps.
We review publicly available information on our counterparty in order to review and monitor its
financial stability and assess its ongoing ability to honor its commitments under the interest rate
swap contract. This counterparty is a large financial institution. Furthermore, we have not
experienced, nor do we expect to experience, any difficulty in the counterparty honoring its
respective commitments.
The market risk inherent in our debt positions is the potential change arising from increases or
decreases in interest rates as discussed below.
- 66 -
At December 31, 2010, we had an outstanding principal balance on our 6.25% Senior Notes and 8.25%
Senior Notes of $185 million and $150 million, respectively. A change in interest rates would
generally affect the fair value of the Senior Notes, but not our earnings or cash flows. At
December 31, 2010, the fair value of our 6.25% Senior Notes and 8.25% Senior Notes were $183.2
million and $156.8 million, respectively. We estimate a hypothetical 10% change in the
yield-to-maturity applicable to the 6.25% Senior Notes and 8.25% Senior Notes at December 31, 2010
would result in a change of approximately $4.3 million and $6.3 million, respectively, in the fair
value of the underlying notes.
For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not
the fair value. At December 31, 2010, borrowings outstanding under the Credit Agreement were $159
million. By means of our cash flow hedge, we have effectively converted the variable rate on $155
million of outstanding borrowings to a fixed rate of 5.49%.
At December 31, 2010, our cash and cash equivalents included highly liquid investments with a
maturity of three months or less at the time of purchase. Due to the short-term nature of our cash
and cash equivalents, a hypothetical 10% increase in interest rates would not have a material
effect on the fair market value of our portfolio. Since we have the ability to liquidate this
portfolio, we do not expect our operating results or cash flows to be materially affected by the
effect of a sudden change in market interest rates on our investment portfolio.
Our operations are subject to normal hazards of operations, including fire, explosion and
weather-related perils. We maintain various insurance coverages, including business interruption
insurance, subject to certain deductibles. We are not fully insured against certain risks because
such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do
not justify such expenditures.
We have a risk management oversight committee that is made up of members from our senior
management. This committee monitors our risk environment and provides direction for activities to
mitigate, to an acceptable level, identified risks that may adversely affect the achievement of our
goals.
|
|
|
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 above 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.
- 67 -
|
|
|
Item 8. |
|
Financial Statements and Supplementary Data |
MANAGEMENTS REPORT ON ITS ASSESSMENT OF THE PARTNERSHIPS 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,
2010 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 concludes that, as of December 31, 2010,
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,
2010. That report appears on page 69.
- 68 -
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 2010, 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, 2010, 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, 2010 and 2009, and the related consolidated statements of income, partners equity,
and cash flows for each of the three years in the period ended December 31, 2010, our report dated
February 16, 2011, expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 16, 2011
- 69 -
Index to Consolidated Financial Statements
|
|
|
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|
|
|
Page |
|
|
|
Reference |
|
|
|
|
|
|
|
|
|
71 |
|
|
|
|
|
|
|
|
|
72 |
|
|
|
|
|
|
|
|
|
73 |
|
|
|
|
|
|
|
|
|
74 |
|
|
|
|
|
|
|
|
|
75 |
|
|
|
|
|
|
|
|
|
76 |
|
- 70 -
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, 2010 and 2009, and the related consolidated statements of income,
partners equity, and cash flows for each of the three years in the period ended December 31, 2010.
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, 2010 and 2009, and the related consolidated results of its operations and its cash flows, for
each of the three years in the period ended December 31, 2010 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, 2010, 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 16, 2011 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 16, 2011
- 71 -
Holly Energy Partners, L.P.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In thousands, except unit data) |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
403 |
|
|
$ |
2,508 |
|
Accounts receivable: |
|
|
|
|
|
|
|
|
Trade |
|
|
3,544 |
|
|
|
4,693 |
|
Affiliates |
|
|
18,964 |
|
|
|
14,074 |
|
|
|
|
|
|
|
|
|
|
|
22,508 |
|
|
|
18,767 |
|
|
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
775 |
|
|
|
739 |
|
Current assets of discontinued operations |
|
|
|
|
|
|
2,195 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
23,686 |
|
|
|
24,209 |
|
|
|
|
|
|
|
|
|
|
Properties and equipment, net |
|
|
434,950 |
|
|
|
398,044 |
|
Transportation agreements, net |
|
|
108,489 |
|
|
|
115,436 |
|
Goodwill |
|
|
49,109 |
|
|
|
49,109 |
|
Investment in SLC Pipeline |
|
|
25,437 |
|
|
|
25,919 |
|
Other assets |
|
|
1,602 |
|
|
|
4,128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
643,273 |
|
|
$ |
616,845 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable: |
|
|
|
|
|
|
|
|
Trade |
|
$ |
6,347 |
|
|
$ |
3,860 |
|
Affiliates |
|
|
3,891 |
|
|
|
2,351 |
|
|
|
|
|
|
|
|
|
|
|
10,238 |
|
|
|
6,211 |
|
Accrued interest |
|
|
7,517 |
|
|
|
2,863 |
|
Deferred revenue |
|
|
10,437 |
|
|
|
8,402 |
|
Accrued property taxes |
|
|
1,990 |
|
|
|
1,072 |
|
Other current liabilities |
|
|
1,262 |
|
|
|
1,257 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
31,444 |
|
|
|
19,805 |
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
491,648 |
|
|
|
390,827 |
|
Other long-term liabilities |
|
|
10,809 |
|
|
|
12,349 |
|
|
|
|
|
|
|
|
|
|
Partners Equity: |
|
|
|
|
|
|
|
|
Common unitholders (22,078,509 and 21,141,009 units issued
and outstanding at December 31, 2010 and 2009, respectively) |
|
|
261,317 |
|
|
|
275,553 |
|
Class B subordinated unitholders (937,500 units issued and
outstanding at December 31, 2009) |
|
|
|
|
|
|
21,426 |
|
General partner interest (2% interest) |
|
|
(141,919 |
) |
|
|
(93,974 |
) |
Accumulated other comprehensive loss |
|
|
(10,026 |
) |
|
|
(9,141 |
) |
|
|
|
|
|
|
|
Total partners equity |
|
|
109,372 |
|
|
|
193,864 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity |
|
$ |
643,273 |
|
|
$ |
616,845 |
|
|
|
|
|
|
|
|
See accompanying notes.
- 72 -
Holly Energy Partners, L.P.
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands, except per unit data) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
146,376 |
|
|
$ |
101,395 |
|
|
$ |
85,040 |
|
Third parties |
|
|
35,721 |
|
|
|
45,166 |
|
|
|
23,782 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
182,097 |
|
|
|
146,561 |
|
|
|
108,822 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
52,947 |
|
|
|
44,003 |
|
|
|
38,920 |
|
Depreciation and amortization |
|
|
30,682 |
|
|
|
26,714 |
|
|
|
21,937 |
|
General and administrative |
|
|
7,719 |
|
|
|
7,586 |
|
|
|
6,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91,348 |
|
|
|
78,303 |
|
|
|
67,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
90,749 |
|
|
|
68,258 |
|
|
|
41,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of SLC Pipeline |
|
|
2,393 |
|
|
|
1,919 |
|
|
|
|
|
SLC Pipeline acquisition costs |
|
|
|
|
|
|
(2,500 |
) |
|
|
|
|
Interest income |
|
|
7 |
|
|
|
11 |
|
|
|
118 |
|
Interest expense |
|
|
(34,001 |
) |
|
|
(21,501 |
) |
|
|
(21,763 |
) |
Gain on sale of assets |
|
|
|
|
|
|
|
|
|
|
36 |
|
Other |
|
|
17 |
|
|
|
67 |
|
|
|
990 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,584 |
) |
|
|
(22,004 |
) |
|
|
(20,619 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes |
|
|
59,165 |
|
|
|
46,254 |
|
|
|
20,966 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
(296 |
) |
|
|
(20 |
) |
|
|
(270 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
58,869 |
|
|
|
46,234 |
|
|
|
20,696 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of
noncontrolling interest of $1,579 and $1,278 for
the years ended
December 31, 2009 and 2008, respectively |
|
|
|
|
|
|
5,301 |
|
|
|
4,671 |
|
Gain on sale of interest in Rio Grande Pipeline
Company |
|
|
|
|
|
|
14,479 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations |
|
|
|
|
|
|
19,780 |
|
|
|
4,671 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
58,869 |
|
|
|
66,014 |
|
|
|
25,367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less general partner interest in net income,
including incentive distributions |
|
|
12,152 |
|
|
|
7,947 |
|
|
|
3,913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
46,717 |
|
|
$ |
58,067 |
|
|
$ |
21,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners per unit interest in earnings
basic and diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
2.12 |
|
|
$ |
2.12 |
|
|
$ |
1.04 |
|
Income from discontinued operations |
|
|
|
|
|
|
0.28 |
|
|
|
0.28 |
|
Gain on sale of discontinued operations |
|
|
|
|
|
|
0.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
2.12 |
|
|
$ |
3.18 |
|
|
$ |
1.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partners units outstanding |
|
|
22,079 |
|
|
|
18,268 |
|
|
|
16,291 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
- 73 -
Holly Energy Partners, L.P.
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009(1) |
|
|
2008(1) |
|
|
|
(In thousands) |
|
Cash flows from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
58,869 |
|
|
$ |
66,014 |
|
|
$ |
25,367 |
|
Adjustments to reconcile net income to net cash provided by operating
activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
30,682 |
|
|
|
27,597 |
|
|
|
22,889 |
|
Equity in earnings of SLC Pipeline, net of distributions |
|
|
482 |
|
|
|
(419 |
) |
|
|
|
|
Change in fair value interest rate swaps |
|
|
1,464 |
|
|
|
175 |
|
|
|
2,282 |
|
Noncontrolling interest in earnings of Rio Grande Pipeline Company |
|
|
|
|
|
|
1,579 |
|
|
|
1,278 |
|
Amortization of restricted and performance units |
|
|
2,214 |
|
|
|
699 |
|
|
|
1,688 |
|
Gain on sale of interest in Rio Grande Pipeline Company |
|
|
|
|
|
|
(14,479 |
) |
|
|
|
|
Gain on sale of assets |
|
|
|
|
|
|
|
|
|
|
(36 |
) |
(Increase) decrease in current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable trade |
|
|
1,149 |
|
|
|
388 |
|
|
|
1,529 |
|
Accounts receivable affiliates |
|
|
(4,890 |
) |
|
|
(4,679 |
) |
|
|
(3,695 |
) |
Prepaid and other current assets |
|
|
(36 |
) |
|
|
(146 |
) |
|
|
(47 |
) |
Current assets of discontinued operations |
|
|
2,195 |
|
|
|
|
|
|
|
|
|
Increase (decrease) in current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable trade |
|
|
2,487 |
|
|
|
(1,956 |
) |
|
|
2,805 |
|
Accounts payable affiliates |
|
|
1,540 |
|
|
|
149 |
|
|
|
(3,819 |
) |
Accrued interest |
|
|
4,654 |
|
|
|
18 |
|
|
|
(151 |
) |
Deferred revenue |
|
|
2,035 |
|
|
|
(7,256 |
) |
|
|
11,958 |
|
Accrued property taxes |
|
|
918 |
|
|
|
(74 |
) |
|
|
(32 |
) |
Other current liabilities |
|
|
5 |
|
|
|
(248 |
) |
|
|
678 |
|
Other, net |
|
|
(600 |
) |
|
|
833 |
|
|
|
957 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
103,168 |
|
|
|
68,195 |
|
|
|
63,651 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to properties and equipment |
|
|
(25,103 |
) |
|
|
(32,999 |
) |
|
|
(42,303 |
) |
Acquisitions of assets from Holly Corporation |
|
|
(35,526 |
) |
|
|
(95,080 |
) |
|
|
(171,000 |
) |
Acquisition of logistics assets from Sinclair Oil Company |
|
|
|
|
|
|
(25,665 |
) |
|
|
|
|
Investment in SLC Pipeline |
|
|
|
|
|
|
(25,500 |
) |
|
|
|
|
Proceeds from sale of interest in Rio Grande Pipeline Company,
net of transferred cash |
|
|
|
|
|
|
31,865 |
|
|
|
|
|
Proceeds from sale of assets |
|
|
|
|
|
|
|
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
Net cash used for investing activities |
|
|
(60,629 |
) |
|
|
(147,379 |
) |
|
|
(213,267 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings under credit agreement |
|
|
66,000 |
|
|
|
239,000 |
|
|
|
285,000 |
|
Repayments of credit agreement borrowings |
|
|
(113,000 |
) |
|
|
(233,000 |
) |
|
|
(85,000 |
) |
Proceeds from issuance of senior notes |
|
|
147,540 |
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common units |
|
|
|
|
|
|
133,301 |
|
|
|
104 |
|
Contribution from general partner |
|
|
|
|
|
|
3,812 |
|
|
|
186 |
|
Distributions to HEP unitholders |
|
|
(84,426 |
) |
|
|
(61,188 |
) |
|
|
(52,426 |
) |
Distributions to noncontrolling interest |
|
|
|
|
|
|
(1,500 |
) |
|
|
(1,800 |
) |
Purchase price in excess of transferred basis in assets
acquired from Holly Corporation |
|
|
(57,560 |
) |
|
|
(3,120 |
) |
|
|
|
|
Purchase of units for restricted grants |
|
|
(2,704 |
) |
|
|
(616 |
) |
|
|
(795 |
) |
Deferred financing costs |
|
|
(494 |
) |
|
|
|
|
|
|
(705 |
) |
Cost of issuing common units |
|
|
|
|
|
|
(266 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used for) financing activities |
|
|
(44,644 |
) |
|
|
76,423 |
|
|
|
144,564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
Decrease for the year |
|
|
(2,105 |
) |
|
|
(2,761 |
) |
|
|
(5,052 |
) |
Beginning of year |
|
|
2,508 |
|
|
|
5,269 |
|
|
|
10,321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
403 |
|
|
$ |
2,508 |
|
|
$ |
5,269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes cash flows attributable
to discontinued operations.
|
See accompanying notes.
- 74 -
Holly Energy Partners, L.P.
Consolidated Statements of Partners Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Holly Energy Partners, L.P. Partners Equity (Deficit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Class B |
|
|
General |
|
|
Other |
|
|
Non- |
|
|
|
|
|
|
Common |
|
|
Subordinated |
|
|
Subordinated |
|
|
Partner |
|
|
Comprehensive |
|
|
controlling |
|
|
|
|
|
|
Units |
|
|
Units |
|
|
Units |
|
|
Interest |
|
|
Loss |
|
|
Interest |
|
|
Total |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007 |
|
$ |
172,807 |
|
|
$ |
(73,725 |
) |
|
$ |
22,973 |
|
|
$ |
(94,239 |
) |
|
$ |
|
|
|
$ |
10,740 |
|
|
$ |
38,556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common units |
|
|
9,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,104 |
|
Cost of issuing common units |
|
|
(71 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(71 |
) |
Capital contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
186 |
|
|
|
|
|
|
|
|
|
|
|
186 |
|
Distributions to HEP unitholders |
|
|
(24,788 |
) |
|
|
(20,720 |
) |
|
|
(2,775 |
) |
|
|
(4,143 |
) |
|
|
|
|
|
|
|
|
|
|
(52,426 |
) |
Distributions to noncontrolling
interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,800 |
) |
|
|
(1,800 |
) |
Purchase of units for
restricted grants |
|
|
(795 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(795 |
) |
Amortization of restricted and
performance units |
|
|
1,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,688 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
11,181 |
|
|
|
9,386 |
|
|
|
1,257 |
|
|
|
3,543 |
|
|
|
|
|
|
|
1,278 |
|
|
|
26,645 |
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,967 |
) |
|
|
|
|
|
|
(12,967 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
11,181 |
|
|
|
9,386 |
|
|
|
1,257 |
|
|
|
3,543 |
|
|
|
(12,967 |
) |
|
|
1,278 |
|
|
|
13,678 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008 |
|
|
169,126 |
|
|
|
(85,059 |
) |
|
|
21,455 |
|
|
|
(94,653 |
) |
|
|
(12,967 |
) |
|
|
10,218 |
|
|
|
8,120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common units |
|
|
186,801 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
186,801 |
|
Cost of issuing common units |
|
|
(266 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(266 |
) |
Conversion of subordinated units |
|
|
(90,824 |
) |
|
|
90,824 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,812 |
|
|
|
|
|
|
|
|
|
|
|
3,812 |
|
Distributions to HEP unitholders |
|
|
(35,245 |
) |
|
|
(16,275 |
) |
|
|
(2,925 |
) |
|
|
(6,743 |
) |
|
|
|
|
|
|
|
|
|
|
(61,188 |
) |
Distributions to noncontrolling
interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,500 |
) |
|
|
(1,500 |
) |
Purchase price in excess of
transferred basis in assets
acquired from Holly
Corporation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,120 |
) |
|
|
|
|
|
|
|
|
|
|
(3,120 |
) |
Purchase of units for restricted
grants |
|
|
(616 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(616 |
) |
Amortization of restricted and
performance units |
|
|
699 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
699 |
|
Elimination of noncontrolling
interest upon sale of Rio
Grande |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,297 |
) |
|
|
(10,297 |
) |
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
45,878 |
|
|
|
10,510 |
|
|
|
2,896 |
|
|
|
6,730 |
|
|
|
|
|
|
|
1,579 |
|
|
|
67,593 |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,826 |
|
|
|
|
|
|
|
3,826 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
45,878 |
|
|
|
10,510 |
|
|
|
2,896 |
|
|
|
6,730 |
|
|
|
3,826 |
|
|
|
1,579 |
|
|
|
71,419 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2009 |
|
|
275,553 |
|
|
|
|
|
|
|
21,426 |
|
|
|
(93,974 |
) |
|
|
(9,141 |
) |
|
|
|
|
|
|
193,864 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of Class B
subordinated units |
|
|
20,588 |
|
|
|
|
|
|
|
(20,588 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to HEP unitholders |
|
|
(81,218 |
) |
|
|
|
|
|
|
(1,519 |
) |
|
|
(1,689 |
) |
|
|
|
|
|
|
|
|
|
|
(84,426 |
) |
Purchase price in excess of
transferred basis in assets
acquired from Holly
Corporation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(57,560 |
) |
|
|
|
|
|
|
|
|
|
|
(57,560 |
) |
Purchase of units for restricted
grants |
|
|
(2,704 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,704 |
) |
Amortization of restricted and
performance units |
|
|
2,214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,214 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
46,884 |
|
|
|
|
|
|
|
681 |
|
|
|
11,304 |
|
|
|
|
|
|
|
|
|
|
|
58,869 |
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(885 |
) |
|
|
|
|
|
|
(885 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
46,884 |
|
|
|
|
|
|
|
681 |
|
|
|
11,304 |
|
|
|
(885 |
) |
|
|
|
|
|
|
57,984 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2010 |
|
$ |
261,317 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(141,919 |
) |
|
$ |
(10,026 |
) |
|
$ |
|
|
|
$ |
109,372 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
- 75 -
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010
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 34% 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 and
terminals, tankage and loading rack facilities.
We own and operate petroleum product and crude oil pipelines and terminal, tankage and loading rack
facilities that support Hollys refining and marketing operations in west Texas, New Mexico, Utah,
Oklahoma, Idaho and Arizona. We also own and operate refined product pipelines and terminals,
located primarily in Texas, that service Alon USA, Inc.s (Alon) refinery in Big Spring, Texas.
Additionally, we own a 25% joint venture interest in a 95-mile intrastate crude oil pipeline system
(the SLC Pipeline) that serves refineries in the Salt Lake City area.
We generate revenues by charging tariffs for transporting petroleum products and crude oil through
our pipelines, by charging fees for terminalling refined products and other hydrocarbons and
storing and providing other services at our storage tanks and terminals. We do not take ownership
of products that we transport, terminal or store, and therefore, we are not directly exposed to
changes in commodity prices.
Principles of Consolidation and Common Control Transactions
The consolidated financial statements include our accounts and those of our subsidiaries. All
significant inter-company transactions and balances have been eliminated.
The pipeline and terminal assets that Holly contributed to us concurrently with the completion of
our initial public offering in 2004, the intermediate pipeline assets purchased from Holly in July
2005 and the various pipeline and logistic asset purchases from Holly in 2009 and 2010 (see Note 3)
occurred while we were a consolidated variable interest entity of Holly. Therefore, as an entity
under common control with Holly, we recorded these assets on our balance sheets at Hollys
historical basis instead of our purchase price or fair value.
If these assets had been acquired from third parties, our acquisition cost in excess of Hollys
basis in the transferred assets of $218 million would have been recorded as increases to our
properties and equipment and intangible assets instead of reductions to our partners equity.
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.
- 76 -
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. Properties and equipment acquired from Holly while
under common control of Holly are stated at Hollys historical basis. Depreciation is provided by
the straight-line method over the estimated useful lives of the assets; primarily 25 years for
terminal facilities, 25 to 32 years for pipelines and 5 to 10 years for corporate and other assets.
Maintenance, repairs and major replacements are generally expensed as incurred. Costs of
replacements constituting improvements are capitalized.
Transportation Agreements
The transportation agreement assets are stated at acquisition date fair value and are being
amortized over the periods of the agreements using the straight-line method. See Note 6 for
additional information on our transportation agreements.
Goodwill
Goodwill represents the excess of our cost of an acquired business over the fair value of the
assets acquired, less liabilities assumed. Goodwill is not amortized and is tested for impairment
annually or more frequently if events or changes in circumstances indicate goodwill may be
impaired. See Sinclair Logistics and Storage Assets Transaction under Note 3 for information on
our goodwill acquired in 2009.
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.
There were no impairments of our long-lived assets, including goodwill, during the years ended
December 31, 2010, 2009 and 2008.
Investment in SLC Pipeline
We account for our 25% SLC Pipeline joint venture interest using the equity method of accounting,
whereby we record our pro-rata share of earnings of the SLC Pipeline, and contributions to and
distributions from the SLC Pipeline as adjustments to our investment balance. As of December 31,
2010, our underlying equity in the SLC Pipeline was $61.2 million compared to our recorded
investment balance of $25.4 million, a difference of $35.8 million. This is attributable to the
difference between our contributed capital and our allocated equity at formation of the SLC
Pipeline. We are amortizing this difference as an adjustment to our pro-rata share of earnings.
- 77 -
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,
2010, an asset retirement obligation of $0.7 million is included in Other long-term liabilities
in our consolidated balance sheets.
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 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.
We have additional pipeline transportation revenues under 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 or other sources are included in other assets to the extent such recoveries are
considered probable. At December 31, 2010 and 2009, we had accruals for environmental remediation
obligations of $0.3 million and $0.2 million, respectively.
Income Tax
We are subject to the Texas margin tax that 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.
- 78 -
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 our previously outstanding 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 unit holders) 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.
Note 2: Discontinued Operations
On December 1, 2009, we sold our 70% interest in Rio Grande to a subsidiary of Enterprise Products
Partners LP for $35 million. Results of operations of Rio Grande and the $14.5 million gain on the
sale are presented in discontinued operations.
In accounting for the sale, we recorded a gain of $14.5 million and a receivable of $2.2 million
that represented our final distribution from Rio Grande. Our recorded net asset balance of Rio
Grande at December 1, 2009, was $22.7 million, consisting of cash of $3.1 million, $29.9 million in
properties and equipment, net and $10.3 million in equity, representing BP, Plcs 30%
noncontrolling interest.
Cash flows from discontinued operations have been combined with cash flows from continuing
operations for presentation purposes in the Consolidated Statements of Cash Flows. For the years
ended December 31, 2009 and 2008, net cash flows from our discontinued Rio Grande operations were
$37.6 million and $3.5 million, respectively. Net cash flows from discontinued operations for 2009
include $35 million in proceeds received upon the sale of our Rio Grande interest.
Note 3: Acquisitions
2010 Acquisitions
Tulsa East / Lovington Storage Asset Transaction
On March 31, 2010, we acquired from Holly certain storage assets for $88.6 million consisting of
hydrocarbon storage tanks having approximately 2 million barrels of storage capacity, a rail
loading rack and a truck unloading rack located at Hollys Tulsa refinery east facility.
In connection with this purchase, we amended our 15-year pipeline, tankage and loading rack
throughput agreement with Holly (the Holly PTTA) that initially pertained to the logistics and
storage assets acquired from an affiliate of Sinclair Oil Company (Sinclair) in December 2009.
Under the amended Holly PTTA, Holly has agreed to transport, throughput and load volumes of product
through our Tulsa east facility logistics and storage assets that will result in minimum annualized
revenues to us of $27.2 million.
Also, as part of this same transaction, we acquired Hollys asphalt loading rack facility located
at its Navajo refinery facility in Lovington, New Mexico for $4.4 million and entered into a
15-year asphalt facility throughput agreement (the Holly ATA). Under the Holly ATA, Holly has
agreed to throughput a minimum volume of products via our Lovington asphalt loading rack facility
that will result in minimum annualized revenues to us of $0.5 million.
- 79 -
See Note 11 for additional information on our long-term transportation agreements with Holly.
In accounting for these acquisitions from Holly, we recorded total property and equipment at
Hollys historical basis of $35.5 million and the purchase price in excess of Hollys basis in the
assets of $57.6 million as a decrease to our partners equity.
2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, we acquired from an affiliate of Sinclair storage tanks having approximately
1.4 million barrels of storage capacity and loading racks at its refinery located in Tulsa,
Oklahoma for $79.2 million. The purchase price consisted of $25.7 million in cash, including $4.2
million in taxes and 1,373,609 of our common units having a fair value of $53.5 million.
Separately, Holly, also a party to the transaction acquired Sinclairs Tulsa refinery.
With respect to this purchase, we recorded $30.2 million in properties and equipment, $49.1 million
in goodwill and $0.2 million in other long-term liabilities. The value of the acquired assets,
which does not include goodwill, is based on fair value using a cost approach methodology.
Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, we acquired from Holly two newly constructed pipelines for $46.5 million,
consisting of a 65-mile, 16-inch crude oil pipeline (the Roadrunner Pipeline) that connects the
Navajo refinery facility located in Lovington, New Mexico to a terminus of Centurion Pipeline
L.P.s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil
pipeline that connects our New Mexico crude oil gathering system to the Navajo refinery Lovington
facility (the Beeson Pipeline).
Tulsa West Loading Racks Transaction
On August 1, 2009, we acquired from Holly for $17.5 million certain truck and rail
loading/unloading facilities located at Hollys Tulsa refinery west facility. The racks load
refined products and lube oils produced at the Tulsa refinery onto rail cars and/or tanker trucks.
Lovington-Artesia Pipeline Transaction
On June 1, 2009, we acquired from Holly a newly constructed 16-inch intermediate pipeline for $34.2
million. The pipeline runs 65 miles from the Navajo refinerys crude oil distillation and vacuum
facilities in Lovington, New Mexico to its petroleum refinery located in Artesia, New Mexico.
In accounting for our 2009 acquisitions from Holly, consisting of the Roadrunner and Beeson
Pipelines, the Tulsa west loading rack facilities and 16-inch intermediate pipeline as discussed
above, we recorded total property and equipment of $95.1 million representing Hollys historical
basis in the transferred assets. The $3.1 million aggregate purchase price in excess of Hollys
historical basis in the assets was recorded as a decrease to our partners equity.
SLC Pipeline Joint Venture Interest
On March 1, 2009, we acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile
intrastate pipeline system that we jointly own with All American Pipeline, L.P. (Plains). The
total cost of our investment in the SLC Pipeline was $28 million, consisting of the capitalized
$25.5 million joint venture contribution and the $2.5 million finders fee paid to Holly that was
expensed as acquisition costs.
2008 Acquisition
Crude Pipelines and Tankage Transaction
On February 29, 2008, we acquired from Holly certain crude pipeline and tankage assets for $180
million, consisting of crude oil trunk lines that support the Navajo refinery, crude oil and
product pipelines that support the Woods Cross refinery, on-site crude tankage located at the
Navajo and Woods Cross refinery complexes, a jet fuel products pipeline running between Artesia and
Roswell, New Mexico and a leased jet fuel terminal in Roswell, New Mexico. The consideration paid
consisted of $171 million in cash and 217,497 of our common units having a fair value of $9
million.
- 80 -
At the time of this transaction, we were not a consolidated variable interest entity of Holly.
Since we were not under common control with Holly, we recorded the acquired assets at fair value.
We recorded property and equipment of $105.8 million and a long-term transportation agreement of
$74.2 million based on values derived using cost and income approach methodologies.
Note 4: Financial Instruments
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts
payable, debt and interest rate swaps. The carrying amounts of cash and cash equivalents, accounts
receivable and accounts payable approximate fair value due to the short-tem maturity of these
instruments.
Our debt consists of outstanding principal under our $300 million revolving credit agreement (the
Credit Agreement), our 6.25% senior notes due 2015 (the 6.25% Senior Notes) and our 8.25%
senior notes due 2018 (the 8.25% Senior Notes). The $159 million carrying amount of outstanding
debt under the Credit Agreement approximates fair value as interest rates are reset frequently
using current rates. The estimated fair value of our 6.25% Senior Notes and 8.25% Senior Notes was
$183.2 million and $156.8 million, respectively, at December 31, 2010. These fair value estimates
are based on market quotes provided from a third-party bank. See Note 8 for additional information
on these instruments.
Fair Value Measurements
Fair value measurements are derived using inputs, (assumptions that market participants would use
in pricing an asset or liability), including assumptions about risk. GAAP categorizes inputs used
in fair value measurements into three broad levels as follows:
|
|
|
(Level 1) Quoted prices in active markets for identical assets or liabilities. |
|
|
|
(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted
prices for similar assets and liabilities in active markets, similar assets and liabilities
in markets that are not active or can be corroborated by observable market data. |
|
|
|
(Level 3) Unobservable inputs that are supported by little or no market activity and
that are significant to the fair value of the assets or liabilities. This includes
valuation techniques that involve significant unobservable inputs. |
We have an interest rate swap that is measured at fair value on a recurring basis using Level 2
inputs that as of December 31, 2010, represented a liability having a fair value of $10 million.
With respect to this instrument, fair value is based on the net present value of expected future
cash flows related to both variable and fixed rate legs of our interest rate swap agreement. Our
measurement is computed using the forward London Interbank Offered Rate (LIBOR) yield curve, a
market-based observable input. See Note 8 for additional information on our interest rate swap.
Note 5: Properties and Equipment
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
Pipelines and terminals (1) |
|
$ |
507,260 |
|
|
$ |
455,075 |
|
Land and right of way |
|
|
25,264 |
|
|
|
25,230 |
|
Other |
|
|
14,591 |
|
|
|
12,528 |
|
Construction in progress |
|
|
16,601 |
|
|
|
10,484 |
|
|
|
|
|
|
|
|
|
|
|
563,716 |
|
|
|
503,317 |
|
Less accumulated depreciation |
|
|
128,766 |
|
|
|
105,273 |
|
|
|
|
|
|
|
|
|
|
$ |
434,950 |
|
|
$ |
398,044 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We periodically evaluate estimated useful lives of our properties and
equipment. Effective January 1, 2010, we revised the estimated useful
lives of our terminal assets to 16 to 25 years. This change in estimated
useful lives resulted in a $3 million reduction in depreciation expense
for the year ended December 31, 2010. |
- 81 -
During the years ended December 31, 2010 and 2009 we capitalized $0.5 million and $1 million,
respectively, in interest related to major construction projects.
Depreciation expense was $23.7 million, $19.7 million and $15.8 million for the years ended
December 31, 2010, 2009 and 2008, respectively.
Note 6: Transportation Agreements
Our transportation agreements consist of the following:
|
|
|
The Alon pipelines and terminals agreement (the Alon PTA) represents a portion of the
total purchase price of the Alon assets acquired in 2005 that was allocated based on an
estimated fair value derived under an income approach. This asset is being amortized over
30 years ending 2035, the 15-year initial term of the Alon PTA plus the expected 15-year
extension period. |
|
|
|
The Holly crude pipelines and tankage agreement (the Holly CPTA) represents a portion
of the total purchase price of certain crude pipelines and tankage assets acquired from
Holly in 2008 that was allocated using a fair value based on the 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, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
Alon transportation agreement |
|
$ |
59,933 |
|
|
$ |
59,933 |
|
Holly crude pipelines and tankage agreement |
|
|
74,231 |
|
|
|
74,231 |
|
|
|
|
|
|
|
|
|
|
|
134,164 |
|
|
|
134,164 |
|
Less accumulated amortization |
|
|
25,675 |
|
|
|
18,728 |
|
|
|
|
|
|
|
|
|
|
$ |
108,489 |
|
|
$ |
115,436 |
|
|
|
|
|
|
|
|
Amortization expense was $6.9 million, $7 million and $6.1 million for the years ended
December 31, 2010, 2009 and 2008, respectively.
We have additional transportation agreements with Holly that relate to pipeline, terminal and
tankage assets contributed to us or acquired from Holly. These transfers occurred while we were a
consolidated variable interest entity of Holly, therefore, our basis in these assets reflect
Hollys historical cost and does not reflect a step-up in basis to fair value.
In addition, we have an agreement to provide transportation and storage services to Holly via our
Tulsa logistics and storage assets acquired from Sinclair. Since this agreement is with Holly and
not between Sinclair and us, there is no purchase price allocation attributable to this agreement.
Note 7: Employees, Retirement and Incentive Plans
Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C., a
Holly subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits and other
direct costs are charged to us monthly in accordance with an omnibus agreement that we have with
Holly. These employees participate in the retirement and benefit plans of Holly. Our share of
retirement and benefit plan costs was $2.9 million, $2.8 million and $2.1 million for the years
ended December 31, 2010, 2009 and 2008, respectively. These amounts include retirement costs of
$1.5 million, $1.6 million and $1.1 million for the years ended December 31, 2010, 2009 and 2008,
respectively.
- 82 -
We have adopted an incentive plan (Long-Term Incentive Plan) for employees, consultants and
non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four
components: restricted units, performance units, unit options and unit appreciation rights.
As of December 31, 2010, we have two types of equity-based compensation, which are described below.
The compensation cost charged against income for these plans was $2.2 million, $1.2 million and
$1.9 million for the years ended December 31, 2010, 2009 and 2008, respectively. We currently
purchase units in the open market instead of issuing new units for settlement of restricted unit
grants. At December 31, 2010, 350,000 units were authorized to be granted under the equity-based
compensation plans, of which 169,939 had not yet been granted.
Restricted Units
Under our Long-Term Incentive Plan, we grant restricted units to selected employees and directors
who perform services for us, with vesting generally over a period of one to five years. Although
full ownership of the units does not transfer to the recipients until the units vest, the
recipients have distribution and voting rights on these units from the date of grant. The fair
value of each restricted unit award is measured at the market price as of the date of grant and is
being amortized over the vesting period.
A summary of restricted unit activity and changes during the year ended December 31, 2010 is
presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
Average |
|
|
Aggregate |
|
|
|
|
|
|
|
Average |
|
|
Remaining |
|
|
Intrinsic |
|
|
|
|
|
|
|
Grant-Date |
|
|
Contractual |
|
|
Value |
|
Restricted Units |
|
Grants |
|
|
Fair Value |
|
|
Term |
|
|
($000) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at January 1, 2010 (not vested) |
|
|
53,271 |
|
|
$ |
34.31 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
36,755 |
|
|
|
43.13 |
|
|
|
|
|
|
|
|
|
Vesting and transfer of full ownership to recipients |
|
|
(41,505 |
) |
|
|
38.53 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(1,226 |
) |
|
|
34.28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2010 (not vested) |
|
|
47,295 |
|
|
$ |
37.47 |
|
|
0.8 year |
|
$ |
2,408 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of restricted units that were vested and transferred to recipients during the years
ended December 31, 2010, 2009 and 2008 was $1.6 million, $1.2 million and $0.8 million,
respectively. As of December 31, 2010, there was $0.5 million of total unrecognized compensation
costs related to nonvested restricted unit grants. That cost is expected to be recognized over a
weighted-average period of 0.8 year.
During the year ended December 31, 2010, we paid $2.7 million for the purchase of 62,352 of our
common units in the open market for the recipients of our restricted unit grants.
Performance Units
Under our Long-Term Incentive Plan, we grant performance units to selected executives who perform
services for us. Performance units granted in 2010 are payable based upon the growth in
distributable cash flow per common unit over the performance period, and vest over a period of
three years. Performance units granted in 2009 and 2008 are payable based upon the growth in
distributions on our common units during the requisite period, and vest over a period of three
years. As of December 31, 2010, estimated share payouts for outstanding nonvested performance unit
awards ranged from 110% to 120%.
We granted 16,965 performance units to certain officers in March 2010. These units will vest over
a three-year performance period ending December 31, 2012 and are payable in HEP common units. The
number of units actually earned will be based on the growth of distributable cash flow per common
unit
over the performance period, and can range from 50% to 150% of the number of performance units
granted. The fair value of these performance units is based on the grant date closing unit price
of $42.59 and will apply to the number of units ultimately awarded.
- 83 -
A summary of performance unit activity and changes during the year ended December 31, 2010 is
presented below:
|
|
|
|
|
|
|
Payable |
|
Performance Units |
|
In Units |
|
|
|
|
|
|
Outstanding at January 1, 2010 (not vested) |
|
|
54,771 |
|
Granted |
|
|
16,965 |
|
Vesting and payment of units to recipients |
|
|
(12,321 |
) |
Forfeited |
|
|
|
|
|
|
|
|
Outstanding at December 31, 2010 (not vested) |
|
|
59,415 |
|
|
|
|
|
The fair value of performance units vested and transferred to recipients during the years
ended December 31, 2010, 2009 and 2008 was $0.6 million, $0.4 million and $0.1 million,
respectively. Based on the weighted average fair value at December 31, 2010 of $32.97, 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 year.
Note 8: Debt
Credit Agreement
At December 31, 2010, the Credit Agreement consisted of a $300 million senior secured revolving
credit facility expiring in August 2011. During the year ended December 31, 2010, we received
advances totaling $66 million and repaid $113 million, resulting in the net repayment of $47
million in advances under the Credit Agreement and an outstanding balance of $159 million at
December 31, 2010. These advances were used to finance acquisitions and capital projects. As of
December 31, 2010, we had no working capital borrowings.
On February 14, 2011 we amended the Credit Agreement, slightly reducing the size of the credit
facility from $300 million to $275 million (the Amended Credit Agreement). The size was reduced
based on managements review of past and forecasted utilization of the facility. The Amended Credit
Agreement expires in February 2016; provided that the Amended Credit Agreement will expire on
September 1, 2014 in the event that, on or prior to such date, the 6.25% Senior Notes have not been
repurchased, refinanced, extended or repaid. The Amended Credit Agreement is available to fund
capital expenditures, investments, acquisitions, distribution payments and working capital and for
general partnership purposes. The Amended Credit Agreement is available to fund letters of credit
up to a $50 million sub-limit and to fund distributions to unitholders up to a $30 million
sub-limit.
Our obligations under the Amended Credit Agreement are collateralized by substantially all of our
assets. Indebtedness under the Amended Credit Agreement is recourse to HEP Logistics Holdings,
L.P., our general partner, and guaranteed by our material, wholly-owned subsidiaries. Any recourse
to HEP Logistics Holdings, L.P. would be limited to the extent of its assets, which other than its
investment in us, are not significant.
We may prepay all loans at any time without penalty, except for payment of certain breakage and
related costs.
Indebtedness under the Amended Credit Agreement bears interest, at our option, at either (a) the
reference rate as announced by the administrative agent plus an applicable margin (ranging from
1.00% to 2.00%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 2.00% to
3.00%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined
in the Amended Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and
amortization, as defined in the Amended Credit Agreement). We incur a commitment fee on the unused
portion of the Amended Credit Agreement at a rate ranging from 0.375% to 0.50% based upon the ratio
of our funded debt to
EBITDA for the four most recently completed fiscal quarters.
- 84 -
The Amended Credit Agreement imposes certain requirements on us which we are subject to and
currently in compliance with, including: a prohibition against distribution to unitholders if,
before or after the distribution, a potential default or an event of default as defined in the
agreement would occur; limitations on our ability to incur debt, make loans, acquire other
companies, change the nature of our business, enter a merger or consolidation, or sell assets; and
covenants that require maintenance of a specified EBITDA to interest expense ratio, total debt to
EBITDA ratio and senior debt to EBITDA ratio. If an event of default exists under the Amended
Credit Agreement, the lenders will be able to accelerate the maturity of the debt and exercise
other rights and remedies.
Senior Notes
In March 2010, we issued $150 million in aggregate principal amount outstanding of 8.25% Senior
Notes maturing March 15, 2018. A portion of the $147.5 million in net proceeds received was used
to fund our $93 million purchase of the Tulsa and Lovington storage assets from Holly on March 31,
2010. Additionally, we used a portion to repay $42 million in outstanding Credit Agreement
borrowings, with the remaining proceeds available for general partnership purposes, including
working capital and capital expenditures.
Our 6.25% Senior Notes having an aggregate principal amount outstanding of $185 million mature
March 1, 2015 and are registered with the SEC. The 6.25% Senior Notes and 8.25% Senior Notes
(collectively, the Senior Notes) are unsecured and 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 its assets, which other than its investment in us,
are not significant.
Our purchase and contribution agreements with Holly with respect to the intermediate pipelines and
the crude pipelines and tankage assets restrict us from selling pipelines and terminals acquired
from Holly and from prepaying borrowings and long-term debt to outstanding balances below $35
million and $171 million prior to 2015 and 2018, respectively, in each case subject to certain
limited exceptions.
Long-term Debt
The carrying amounts of our long-term debt are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
Credit Agreement |
|
$ |
159,000 |
|
|
$ |
206,000 |
|
|
|
|
|
|
|
|
|
|
6.25% Senior Notes |
|
|
|
|
|
|
|
|
Principal |
|
|
185,000 |
|
|
|
185,000 |
|
Unamortized discount |
|
|
(1,584 |
) |
|
|
(1,964 |
) |
Unamortized premium dedesignated fair value hedge |
|
|
1,444 |
|
|
|
1,791 |
|
|
|
|
|
|
|
|
|
|
|
184,860 |
|
|
|
184,827 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.25% Senior Notes |
|
|
|
|
|
|
|
|
Principal |
|
|
150,000 |
|
|
|
|
|
Unamortized discount |
|
|
(2,212 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
147,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
491,648 |
|
|
$ |
390,827 |
|
|
|
|
|
|
|
|
- 85 -
Interest Rate Risk Management
We use interest rate swaps (derivative instruments) to manage our exposure to interest rate risk.
As of December 31, 2010, we have an interest rate swap that hedges our exposure to the cash flow
risk caused by the effects of LIBOR changes on a $155 million Credit Agreement advance. This
interest rate swap effectively converts $155 million of our LIBOR based debt to fixed rate debt
having an interest rate of 3.74% plus an applicable margin of 1.75%, which equaled an effective
interest rate of 5.49% as of December 31, 2010. This swap contract matures in February 2013.
We have designated this interest rate swap as a cash flow hedge. Based on our assessment of
effectiveness using the change in variable cash flows method, we have determined that this interest
rate swap is effective in offsetting the variability in interest payments on $155 million of our
variable rate debt resulting from changes in LIBOR. Under hedge accounting, we adjust our cash
flow hedge on a quarterly basis to its fair value with the offsetting fair value adjustment to
accumulated other comprehensive loss. Also on a quarterly basis, we measure hedge effectiveness by
comparing the present value of the cumulative change in the expected future interest to be paid or
received on the variable leg of our swap against the expected future interest payments on $155
million of our variable rate debt. Any ineffectiveness is reclassified from accumulated other
comprehensive loss to interest expense. To date, we have had no ineffectiveness on our cash flow
hedge.
Additional information on our interest rate swaps are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
|
|
|
|
Location of Offsetting |
|
|
Offsetting |
|
Derivative Instrument |
|
Location |
|
|
Fair Value |
|
|
Balance |
|
|
Amount |
|
|
|
(In thousands) |
|
December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swap designated as cash flow hedging instrument: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable-to-fixed interest rate swap contract
($155 million of LIBOR based debt interest) |
|
Other long-term liabilities |
|
$ |
10,026 |
|
|
Accumulated other comprehensive loss |
|
$ |
10,026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
Fair |
|
|
Location of Offsetting |
|
|
Offsetting |
|
Derivative Instrument |
|
Location |
|
|
Value |
|
|
Balance |
|
|
Amount |
|
|
|
(In thousands) |
|
December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swap designated as cash flow hedging instrument: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable-to-fixed interest rate swap contract
($171 million of LIBOR based debt interest) |
|
Other long-term liabilities |
|
$ |
9,141 |
|
|
Accumulated other comprehensive loss |
|
$ |
9,141 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-variable interest rate swap contract
($60 million of 6.25% Senior Notes interest) |
|
Other assets |
|
$ |
2,294 |
|
|
Long-term debt |
|
$ |
1,791 |
(1) |
|
|
|
|
|
|
|
|
|
|
Equity |
|
|
503 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,294 |
|
|
|
|
|
|
$ |
2,294 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable-to-fixed interest rate swap contract
($60 million of 6.25% Senior Notes interest) |
|
Other long-term liabilities |
|
$ |
2,555 |
|
|
Equity |
|
$ |
2,555 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents unamortized balance of deferred hedge premium. |
|
(2) |
|
Represents prior year charges to interest expense. |
In May 2010, we repaid $16 million of our Credit Agreement debt and also settled a
corresponding portion of our interest rate swap agreement having a notional amount of $16 million
for $1.1 million. Upon payment, we reduced our swap liability and reclassified a $1.1 million
charge from accumulated other comprehensive loss to interest expense, representing the application
of hedge accounting prior to settlement.
In the first quarter of 2010, we settled two interest rate swaps. We had an interest rate swap
contract that effectively converted interest expense associated with $60 million of our 6.25%
Senior Notes from fixed to variable rate debt (Variable Rate Swap). We had an additional
interest rate swap contract that effectively unwound the effects of the Variable Rate Swap,
converting $60 million of the previously hedged long-term debt back to fixed rate debt (Fixed Rate
Swap), effectively fixing interest at a 4.75%
rate. Upon settlement of the Variable Rate and Fixed Rate Swaps, we received $1.9 million and paid
$3.6 million, respectively.
- 86 -
For the years ended December 31, 2010, 2009 and 2008, we recognized $1.5 million, $0.2 million and
$2.3 million, respectively, in non-cash charges to interest expense as a result of fair value
adjustments to our interest rate swaps.
We have a deferred hedge premium that relates to the application of hedge accounting to the
Variable Rate Swap prior to its hedge dedesignation in 2008. This deferred hedge premium having a
balance of $1.4 million at December 31, 2010, is being amortized as a reduction to interest expense
over the remaining term of the 6.25% Senior Notes.
Interest Expense and Other Debt Information
Interest expense consists of the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Interest on outstanding debt: |
|
|
|
|
|
|
|
|
|
|
|
|
Credit Agreement, net of interest on interest rate swap |
|
$ |
9,109 |
|
|
$ |
10,657 |
|
|
$ |
8,705 |
|
6.25% Senior Notes, net of interest on interest rate swaps |
|
|
11,404 |
|
|
|
10,703 |
|
|
|
10,454 |
|
8.25% Senior Notes |
|
|
10,298 |
|
|
|
|
|
|
|
|
|
Partial settlement of interest rate swap cash flow hedge |
|
|
1,076 |
|
|
|
|
|
|
|
|
|
Net fair value adjustments to interest rate swaps |
|
|
1,464 |
|
|
|
175 |
|
|
|
2,282 |
|
Net amortization of discount and deferred debt issuance costs |
|
|
713 |
|
|
|
706 |
|
|
|
1,002 |
|
Commitment fees |
|
|
392 |
|
|
|
268 |
|
|
|
327 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest incurred |
|
|
34,456 |
|
|
|
22,509 |
|
|
|
22,770 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less capitalized interest |
|
|
455 |
|
|
|
1,008 |
|
|
|
1,007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense |
|
$ |
34,001 |
|
|
$ |
21,501 |
|
|
$ |
21,763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest (1) |
|
$ |
31,305 |
|
|
$ |
21,721 |
|
|
$ |
19,482 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net of cash received under our interest rate swap agreements of $1.9 million, $3.8
million and $3.8 million for the years ended December 31, 2010, 2009 and 2008,
respectively. |
Note 9: 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.
As of December 31, 2010, 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 |
|
2011 |
|
|
6,545 |
|
2012 |
|
|
6,478 |
|
2013 |
|
|
6,476 |
|
2014 |
|
|
6,420 |
|
2015 |
|
|
6,419 |
|
Thereafter |
|
|
10,086 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
42,424 |
|
|
|
|
|
Rental expense charged to operations was $7.1 million, $7.1 million and $6.5 million for the
years ended December 31, 2010, 2009 and 2008, 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.
- 87 -
Note 10: Significant Customers
All revenues are domestic revenues, of which 92% are currently generated from our two largest
customers: Holly and Alon. The vast majority of our revenues are derived from activities
conducted in the southwest United States.
The following table presents the percentage of total revenues from continuing operations generated
by each of these customers:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Holly |
|
|
80 |
% |
|
|
69 |
% |
|
|
78 |
% |
Alon |
|
|
12 |
% |
|
|
26 |
% |
|
|
17 |
% |
Note 11: Related Party Transactions
We serve Hollys refineries in New Mexico, Utah and Oklahoma under the following long-term pipeline
and terminal, tankage and throughput agreements:
|
|
|
Holly PTA (pipelines and terminals throughput agreement expiring in 2019 that relates to
assets contributed to us by Holly upon our initial public offering in 2004); |
|
|
|
Holly IPA (intermediate pipelines throughput agreement expiring in 2024 that relates to
assets acquired from Holly in 2005 and 2009); |
|
|
|
Holly CPTA (crude pipelines and tankage throughput agreement expiring in 2023 that
relates to assets acquired from Holly in 2008); |
|
|
|
Holly PTTA (pipeline, tankage and loading rack throughput agreement expiring in 2024
that relates to the Tulsa east facilities acquired from Sinclair in 2009 and from Holly in
March 2010); |
|
|
|
Holly RPA (pipeline throughput agreement expiring in 2024 that relates to the Roadrunner
Pipeline acquired from Holly in 2009); |
|
|
|
Holly ETA (equipment and throughput agreement expiring in 2024 that relates to the Tulsa
west facilities acquired from Holly in 2009); |
|
|
|
Holly NPA (natural gas pipeline throughput agreement expiring in 2024); and |
|
|
|
Holly ATA (asphalt loading rack throughput agreement expiring in 2025 that relates to
the Lovington rack facility acquired from Holly in March 2010). |
Under these agreements, Holly agreed to transport, store and throughput volumes of refined product
and crude oil on our pipelines and terminal, tankage and loading rack facilities that result in
minimum annual payments to us. These minimum annual payments or revenues are adjusted each year at
a percentage change based upon the change in the Producer Price Index (PPI) but will not decrease
as a result of a decrease in the PPI. Under these agreements, the agreed upon tariff rates are
adjusted each year on July 1 at a rate based upon the percentage change in the PPI or the Federal
Energy Regulatory Commission (FERC) index, but with the exception of the Holly IPA, generally
will not decrease as a result of a decrease in the PPI or FERC index. The FERC index is the change
in the PPI plus a FERC adjustment factor that is reviewed periodically. Following our July 1, 2010
PPI rate adjustment, these agreements with Holly will result in minimum annualized payments to us
of $133 million.
If Holly fails to meet its minimum volume commitments under the agreements in any quarter, it will
be required to pay us in cash the amount of any shortfall by the last day of the month following
the end of the quarter. A shortfall payment under the Holly PTA and Holly IPA may be applied as a
credit in the following four quarters after minimum obligations are met.
We entered into an omnibus agreement with Holly in 2004 that Holly and we amended and restated
several times in connection with our past acquisitions from Holly with the last amendment and
restatement occurring on March 31, 2010 (the Omnibus Agreement). Under certain provisions of the
Omnibus Agreement, we pay Holly an annual administrative fee for the provision by Holly or its
affiliates of various general and administrative services to us, currently $2.3 million. This fee
does not include the
salaries of pipeline and terminal personnel or the cost of their employee benefits, which are
separately charged to us by Holly. Also, we reimburse Holly and its affiliates for direct expenses
they incur on our behalf.
- 88 -
Related party transactions with Holly are as follows:
|
|
Revenues received from Holly were $146.4 million, $101.4 million and $85 million for the
years ended December 31, 2010, 2009 and 2008, respectively. |
|
|
Holly charged general and administrative services under the Omnibus Agreement of $2.3
million, $2.3 million and $2.2 million for the years ended December 31, 2010, 2009 and 2008,
respectively. |
|
|
We reimbursed Holly for costs of employees supporting our operations of $18.6 million, $17
million and $13.1 million for the years ended December 31, 2010, 2009 and 2008, respectively. |
|
|
Holly reimbursed us $3.7 million and $1.7 million for certain costs paid on their behalf
for the years ended December 31, 2010 and December 31, 2009, respectively. |
|
|
We paid Holly a $2.5 million finders fee in connection the acquisition of our 25% joint
venture interest in the SLC Pipeline in the first quarter of 2009. |
|
|
We distributed $35.9 million, $29.5 million and $25.6 million for the years ended December
31, 2010, 2009 and 2008, respectively, to Holly as regular distributions on its common units,
subordinated units and general partner interest, including general partner incentive
distributions. |
|
|
Accounts receivable from Holly were $19 million and $14.1 million at December 31, 2010 and
2009, respectively. |
|
|
Accounts payable to Holly were $3.9 million and $2.4 million at December 31, 2010 and 2009,
respectively. |
|
|
Revenues for the years ended December 31, 2010, 2009 and 2008 include $3.6 million, $2.4
million and $1.2 million, of shortfalls billed under the Holly IPA in 2009, 2008 and 2007,
respectively, as Holly did not exceed its minimum volume commitment in any of the subsequent
four quarters in 2010, 2009 and 2008. Deferred revenue in the consolidated balance sheets at
December 31, 2010 and 2009 includes $3.3 million and $3.6 million, respectively, relating to
the Holly IPA. It is possible that Holly may not exceed its minimum obligations under the
Holly IPA to allow Holly to receive credit for any of the $3.3 million deferred at December
31, 2010. |
|
|
We acquired various pipeline, terminal and tankage assets from Holly in 2010, 2009 and
2008. See Note 3 for a description of these transactions. |
Note 12: Partners Equity, Income Allocations and Cash Distributions
Holly currently holds 7,290,000 of our common units and the 2% general partner interest, which
together constitutes a 34% ownership interest in us.
In May 2010, all of the conditions necessary to end the subordination period for the 937,500 Class
B subordinated units originally issued to Alon were met and the units were converted into our
common units on a one-for-one basis. These subordinated units were not publicly traded.
Issuances of units
We issued 1,373,609 of our common units having a value of $53.5 million to Sinclair as partial
consideration of our total $79.2 million purchase of Sinclairs Tulsa logistics assets in December
2009.
- 89 -
We issued in a public offering 2,185,000 of our common units priced at $35.78 per unit in November
2009. Aggregate net proceeds of $74.9 million were used to fund the cash portion of our December
2009 asset acquisitions, to repay outstanding borrowings under the Credit Agreement and for general
partnership purposes.
Additionally, we issued in a public offering 2,192,400 of our common units priced at $27.80 per
unit in May 2009. Net proceeds of $58.4 million were used to repay outstanding borrowings under
the Credit Agreement and for general partnership purposes.
We received aggregate capital contributions of $3.8 million from our general partner to maintain
its 2% general partner interest concurrent with the 2009 common unit issuances described above.
Under our registration statement filed with the SEC using a shelf registration process, we
currently have the ability to raise $860 million through security offerings, through one or more
prospectus supplements that would describe, among other things, the specific amounts, prices and
terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of
securities would be used for general business purposes, which may include, among other things,
funding acquisitions of assets or businesses, working capital, capital expenditures, investments in
subsidiaries, the retirement of existing debt and/or the repurchase of common units or other
securities.
Allocations of Net Income
Net income attributable to Holly Energy Partners, L.P. is allocated between limited partners and
the general partner interest in accordance with the provisions of the partnership agreement. HEP
net income allocated to the general partner includes incentive distributions that are declared
subsequent to quarter end. After the amount of incentive distributions is allocated to the general
partner, the remaining net income attributable to HEP is allocated to the partners based on their
weighted average ownership percentage during the period.
The following table presents the allocation of the general partner interest in net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
General partner interest in net income |
|
$ |
971 |
|
|
$ |
1,210 |
|
|
$ |
445 |
|
General partner incentive distribution |
|
|
11,181 |
|
|
|
6,737 |
|
|
|
3,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general partner interest in net
income attributable to HEP |
|
$ |
12,152 |
|
|
$ |
7,947 |
|
|
$ |
3,913 |
|
|
|
|
|
|
|
|
|
|
|
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. The Amended Credit Agreement
prohibits us from making cash distributions if any potential default or event of default, as
defined in the Amended 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 laws, 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 the Amended Credit Agreement and in all
cases are used solely for working capital purposes or to pay distributions to partners.
- 90 -
We make distributions of available cash from operating surplus for any quarter, in the following
manner: 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; and 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, thereafter. Cash in
excess of the minimum quarterly distributions is distributed to the unitholders and the general
partner based on the percentages below.
Our general partner, HEP Logistics Holdings, L.P., is entitled to incentive distributions if the
amount we distribute with respect to any quarter exceeds specified target levels 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 |
% |
On January 26, 2011, we announced our cash distribution for the fourth quarter of 2010 of
$0.845 per unit. The distribution is payable on all common and general partner units and will be
paid February 14, 2011 to all unitholders of record on February 7, 2011.
The following table presents the allocation of our regular quarterly cash distributions to the
general and limited partners for the periods in which they apply. Our distributions are declared
subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid
during the periods presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(in thousands, except per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest |
|
$ |
1,724 |
|
|
$ |
1,356 |
|
|
$ |
1,069 |
|
General partner incentive distribution |
|
|
11,181 |
|
|
|
6,737 |
|
|
|
3,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general partner distribution |
|
|
12,905 |
|
|
|
8,093 |
|
|
|
4,537 |
|
Limited partner distribution |
|
|
73,223 |
|
|
|
59,725 |
|
|
|
49,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total regular quarterly cash distribution |
|
$ |
86,128 |
|
|
$ |
67,818 |
|
|
$ |
53,622 |
|
|
|
|
|
|
|
|
|
|
|
Cash distribution per unit applicable to
limited partners |
|
$ |
3.32 |
|
|
$ |
3.16 |
|
|
$ |
3.00 |
|
|
|
|
|
|
|
|
|
|
|
As a master limited partnership, we distribute our available cash, which has historically
exceeded our net income because depreciation and amortization expense represents a non-cash charge
against income. The result is a decline in our equity since our regular quarterly distributions
have exceeded our quarterly net income. Additionally, if the assets contributed and acquired from
Holly had occurred while we were not a consolidated variable interest entity of Holly, our
acquisition cost in excess of Hollys historical basis in the transferred assets of $218 million
would have been recorded in our financial statements as increases to our properties and equipment
and intangible assets instead of decreases to our partners equity.
- 91 -
Note 13: Comprehensive Income (Loss)
We have other comprehensive income (loss) resulting from fair value adjustments to our cash flow
hedge. Our comprehensive income is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
58,869 |
|
|
$ |
67,593 |
|
|
$ |
26,645 |
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of cash flow hedge |
|
|
(1,961 |
) |
|
|
3,826 |
|
|
|
(12,967 |
) |
Reclassification adjustment to net income on partial
settlement of cash flow hedge |
|
|
1,076 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss) |
|
|
(885 |
) |
|
|
3,826 |
|
|
|
(12,967 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
57,984 |
|
|
|
71,419 |
|
|
|
13,678 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less noncontrolling interest in comprehensive income |
|
|
|
|
|
|
1,579 |
|
|
|
1,278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income attributable to HEP unitholders |
|
$ |
57,984 |
|
|
$ |
69,840 |
|
|
$ |
12,400 |
|
|
|
|
|
|
|
|
|
|
|
Note 14: 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, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
40,696 |
|
|
$ |
45,483 |
|
|
$ |
46,549 |
|
|
$ |
49,369 |
|
|
$ |
182,097 |
|
Operating income |
|
$ |
17,863 |
|
|
$ |
22,484 |
|
|
$ |
24,172 |
|
|
$ |
26,230 |
|
|
$ |
90,749 |
|
Income from continuing operations before
income taxes |
|
$ |
10,796 |
|
|
$ |
13,481 |
|
|
$ |
16,335 |
|
|
$ |
18,553 |
|
|
$ |
59,165 |
|
Net income |
|
$ |
10,702 |
|
|
$ |
13,435 |
|
|
$ |
16,259 |
|
|
$ |
18,473 |
|
|
$ |
58,869 |
|
Limited partners interest in net income |
|
$ |
8,056 |
|
|
$ |
10,526 |
|
|
$ |
13,087 |
|
|
$ |
15,048 |
|
|
$ |
46,717 |
|
Limited partners per unit interest in net
income basic and diluted |
|
$ |
0.36 |
|
|
$ |
0.48 |
|
|
$ |
0.59 |
|
|
$ |
0.68 |
|
|
$ |
2.12 |
|
Distributions per limited partner unit |
|
$ |
0.815 |
|
|
$ |
0.825 |
|
|
$ |
0.835 |
|
|
$ |
0.845 |
|
|
$ |
3.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
29,332 |
|
|
$ |
37,999 |
|
|
$ |
40,805 |
|
|
$ |
38,425 |
|
|
$ |
146,561 |
|
Operating income |
|
$ |
11,640 |
|
|
$ |
18,958 |
|
|
$ |
21,274 |
|
|
$ |
16,386 |
|
|
$ |
68,258 |
|
Income from continuing operations
before income taxes |
|
$ |
3,918 |
|
|
$ |
15,044 |
|
|
$ |
15,569 |
|
|
$ |
11,723 |
|
|
$ |
46,254 |
|
Income from discontinued operations |
|
$ |
1,594 |
|
|
$ |
1,441 |
|
|
$ |
1,070 |
|
|
$ |
15,675 |
|
|
$ |
19,780 |
|
Net income |
|
$ |
5,439 |
|
|
$ |
16,392 |
|
|
$ |
16,539 |
|
|
$ |
27,644 |
|
|
$ |
66,014 |
|
Limited partners interest in net income |
|
$ |
4,146 |
|
|
$ |
14,543 |
|
|
$ |
14,517 |
|
|
$ |
24,861 |
|
|
$ |
58,067 |
|
Limited partners per unit interest in net
income basic and diluted |
|
$ |
0.25 |
|
|
$ |
0.82 |
|
|
$ |
0.78 |
|
|
$ |
1.22 |
|
|
$ |
3.18 |
|
Distributions per limited partner unit |
|
$ |
0.775 |
|
|
$ |
0.785 |
|
|
$ |
0.795 |
|
|
$ |
0.805 |
|
|
$ |
3.16 |
|
Note 15: Supplemental Guarantor / Non-Guarantor Financial Information
Obligations of Holly Energy Partners, L.P. (Parent) under the 6.25% Senior Notes and 8.25% Senior
Notes have been jointly and severally guaranteed by each of its direct and indirect wholly-owned
subsidiaries (Guarantor Subsidiaries). These guarantees are full and unconditional.
We sold our 70% interest in Rio Grande on December 1, 2009; therefore, Rio Grande is no longer a
subsidiary of HEP. Rio Grande (Non-Guarantor) was the only subsidiary that did not guarantee
these obligations. Amounts attributable to Rio Grande prior to our sale are presented in
discontinued operations.
- 92 -
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.
Condensed Consolidating Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
|
|
|
|
|
December 31, 2010 |
|
Parent |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
2 |
|
|
$ |
401 |
|
|
$ |
|
|
|
$ |
403 |
|
Accounts receivable |
|
|
|
|
|
|
22,508 |
|
|
|
|
|
|
|
22,508 |
|
Intercompany accounts receivable (payable) |
|
|
(92,230 |
) |
|
|
92,230 |
|
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
235 |
|
|
|
540 |
|
|
|
|
|
|
|
775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
(91,993 |
) |
|
|
115,679 |
|
|
|
|
|
|
|
23,686 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties and equipment, net |
|
|
|
|
|
|
434,950 |
|
|
|
|
|
|
|
434,950 |
|
Investment in subsidiaries |
|
|
541,262 |
|
|
|
|
|
|
|
(541,262 |
) |
|
|
|
|
Transportation agreements, net |
|
|
|
|
|
|
108,489 |
|
|
|
|
|
|
|
108,489 |
|
Goodwill |
|
|
|
|
|
|
49,109 |
|
|
|
|
|
|
|
49,109 |
|
Investment in SLC Pipeline |
|
|
|
|
|
|
25,437 |
|
|
|
|
|
|
|
25,437 |
|
Other assets |
|
|
1,261 |
|
|
|
341 |
|
|
|
|
|
|
|
1,602 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
450,530 |
|
|
$ |
734,005 |
|
|
$ |
(541,262 |
) |
|
$ |
643,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
|
|
|
$ |
10,238 |
|
|
$ |
|
|
|
$ |
10,238 |
|
Accrued interest |
|
|
7,498 |
|
|
|
19 |
|
|
|
|
|
|
|
7,517 |
|
Deferred revenue |
|
|
|
|
|
|
10,437 |
|
|
|
|
|
|
|
10,437 |
|
Accrued property taxes |
|
|
|
|
|
|
1,990 |
|
|
|
|
|
|
|
1,990 |
|
Other current liabilities |
|
|
1,011 |
|
|
|
251 |
|
|
|
|
|
|
|
1,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
8,509 |
|
|
|
22,935 |
|
|
|
|
|
|
|
31,444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
332,649 |
|
|
|
158,999 |
|
|
|
|
|
|
|
491,648 |
|
Other long-term liabilities |
|
|
|
|
|
|
10,809 |
|
|
|
|
|
|
|
10,809 |
|
Partners equity |
|
|
109,372 |
|
|
|
541,262 |
|
|
|
(541,262 |
) |
|
|
109,372 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity |
|
$ |
450,530 |
|
|
$ |
734,005 |
|
|
$ |
(541,262 |
) |
|
$ |
643,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
|
|
|
|
|
December 31, 2009 |
|
Parent |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
2 |
|
|
$ |
2,506 |
|
|
$ |
|
|
|
$ |
2,508 |
|
Accounts receivable |
|
|
|
|
|
|
18,767 |
|
|
|
|
|
|
|
18,767 |
|
Intercompany accounts receivable (payable) |
|
|
(76,855 |
) |
|
|
76,855 |
|
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
261 |
|
|
|
478 |
|
|
|
|
|
|
|
739 |
|
Current assets of discontinued operations |
|
|
|
|
|
|
2,195 |
|
|
|
|
|
|
|
2,195 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
(76,592 |
) |
|
|
100,801 |
|
|
|
|
|
|
|
24,209 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties and equipment, net |
|
|
|
|
|
|
398,044 |
|
|
|
|
|
|
|
398,044 |
|
Investment in subsidiaries |
|
|
458,381 |
|
|
|
|
|
|
|
(458,381 |
) |
|
|
|
|
Transportation agreements, net |
|
|
|
|
|
|
115,436 |
|
|
|
|
|
|
|
115,436 |
|
Goodwill |
|
|
|
|
|
|
49,109 |
|
|
|
|
|
|
|
49,109 |
|
Investment in SLC Pipeline |
|
|
|
|
|
|
25,919 |
|
|
|
|
|
|
|
25,919 |
|
Other assets |
|
|
3,267 |
|
|
|
861 |
|
|
|
|
|
|
|
4,128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
385,056 |
|
|
$ |
690,170 |
|
|
$ |
(458,381 |
) |
|
$ |
616,845 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
|
|
|
$ |
6,211 |
|
|
$ |
|
|
|
$ |
6,211 |
|
Accrued interest |
|
|
2,849 |
|
|
|
14 |
|
|
|
|
|
|
|
2,863 |
|
Deferred revenue |
|
|
|
|
|
|
8,402 |
|
|
|
|
|
|
|
8,402 |
|
Accrued property taxes |
|
|
|
|
|
|
1,072 |
|
|
|
|
|
|
|
1,072 |
|
Other current liabilities |
|
|
961 |
|
|
|
296 |
|
|
|
|
|
|
|
1,257 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
3,810 |
|
|
|
15,995 |
|
|
|
|
|
|
|
19,805 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
184,827 |
|
|
|
206,000 |
|
|
|
|
|
|
|
390,827 |
|
Other long-term liabilities |
|
|
2,555 |
|
|
|
9,794 |
|
|
|
|
|
|
|
12,349 |
|
Partners equity |
|
|
193,864 |
|
|
|
458,381 |
|
|
|
(458,381 |
) |
|
|
193,864 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity |
|
$ |
385,056 |
|
|
$ |
690,170 |
|
|
$ |
(458,381 |
) |
|
$ |
616,845 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 93 -
Condensed Consolidating Statement of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
|
|
|
|
|
Year ended December 31, 2010 |
|
Parent |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
|
|
|
$ |
146,376 |
|
|
$ |
|
|
|
$ |
146,376 |
|
Third parties |
|
|
|
|
|
|
35,721 |
|
|
|
|
|
|
|
35,721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
182,097 |
|
|
|
|
|
|
|
182,097 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
|
|
|
|
52,947 |
|
|
|
|
|
|
|
52,947 |
|
Depreciation and amortization |
|
|
|
|
|
|
30,682 |
|
|
|
|
|
|
|
30,682 |
|
General and administrative |
|
|
5,053 |
|
|
|
2,666 |
|
|
|
|
|
|
|
7,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,053 |
|
|
|
86,295 |
|
|
|
|
|
|
|
91,348 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(5,053 |
) |
|
|
95,802 |
|
|
|
|
|
|
|
90,749 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of subsidiaries |
|
|
87,280 |
|
|
|
|
|
|
|
(87,280 |
) |
|
|
|
|
Equity in earnings of SLC Pipeline |
|
|
|
|
|
|
2,393 |
|
|
|
|
|
|
|
2,393 |
|
Interest income (expense) |
|
|
(23,358 |
) |
|
|
(10,636 |
) |
|
|
|
|
|
|
(33,994 |
) |
Other |
|
|
|
|
|
|
17 |
|
|
|
|
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63,922 |
|
|
|
(8,226 |
) |
|
|
(87,280 |
) |
|
|
(31,584 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
58,869 |
|
|
|
87,576 |
|
|
|
(87,280 |
) |
|
|
59,165 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
|
|
|
|
(296 |
) |
|
|
|
|
|
|
(296 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
58,869 |
|
|
$ |
87,280 |
|
|
$ |
(87,280 |
) |
|
$ |
58,869 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year ended December 31, 2009 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
|
|
|
$ |
101,395 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
101,395 |
|
Third parties |
|
|
|
|
|
|
45,166 |
|
|
|
|
|
|
|
|
|
|
|
45,166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
146,561 |
|
|
|
|
|
|
|
|
|
|
|
146,561 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
|
|
|
|
44,003 |
|
|
|
|
|
|
|
|
|
|
|
44,003 |
|
Depreciation and amortization |
|
|
|
|
|
|
26,714 |
|
|
|
|
|
|
|
|
|
|
|
26,714 |
|
General and administrative |
|
|
4,697 |
|
|
|
2,889 |
|
|
|
|
|
|
|
|
|
|
|
7,586 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,697 |
|
|
|
73,606 |
|
|
|
|
|
|
|
|
|
|
|
78,303 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(4,697 |
) |
|
|
72,955 |
|
|
|
|
|
|
|
|
|
|
|
68,258 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of subsidiaries |
|
|
81,773 |
|
|
|
3,686 |
|
|
|
|
|
|
|
(85,459 |
) |
|
|
|
|
Equity in earnings of SLC Pipeline |
|
|
|
|
|
|
1,919 |
|
|
|
|
|
|
|
|
|
|
|
1,919 |
|
SLC Pipeline acquisition costs |
|
|
|
|
|
|
(2,500 |
) |
|
|
|
|
|
|
|
|
|
|
(2,500 |
) |
Interest income (expense) |
|
|
(11,062 |
) |
|
|
(10,428 |
) |
|
|
|
|
|
|
|
|
|
|
(21,490 |
) |
Other |
|
|
|
|
|
|
67 |
|
|
|
|
|
|
|
|
|
|
|
67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70,711 |
|
|
|
(7,256 |
) |
|
|
|
|
|
|
(85,459 |
) |
|
|
(22,004 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
before income taxes |
|
|
66,014 |
|
|
|
65,699 |
|
|
|
|
|
|
|
(85,459 |
) |
|
|
46,254 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
|
|
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
66,014 |
|
|
|
65,679 |
|
|
|
|
|
|
|
(85,459 |
) |
|
|
46,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations |
|
|
|
|
|
|
16,094 |
|
|
|
5,265 |
|
|
|
(1,579 |
) |
|
|
19,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
66,014 |
|
|
$ |
81,773 |
|
|
$ |
5,265 |
|
|
$ |
(87,038 |
) |
|
$ |
66,014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 94 -
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 |
|
|
|
|
|
|
23,782 |
|
|
|
|
|
|
|
|
|
|
|
23,782 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
108,822 |
|
|
|
|
|
|
|
|
|
|
|
108,822 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
|
|
|
|
38,920 |
|
|
|
|
|
|
|
|
|
|
|
38,920 |
|
Depreciation and amortization |
|