e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
Commission File Number 1-32225
HOLLY ENERGY PARTNERS, L.P.
Formed under the laws of the State of Delaware
I.R.S. Employer Identification No. 20-0833098
100 Crescent Court, Suite 1600
Dallas, Texas 75201-6915
Telephone Number: (214) 871-3555
Securities registered pursuant to Section 12(b) of the Act:
Common Limited Partner Units
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act.
Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in part III of the Form 10-K
or any amendments to the Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in
Rule 12b-2 of the Exchange Act.
|
|
|
|
|
|
|
Large accelerated filer
o |
|
Accelerated filer
þ |
|
Non-accelerated filer o
(Do not check if a smaller reporting company) |
|
Smaller Reporting Company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
The aggregate market value of common limited partner units held by non-affiliates of the registrant
was approximately $412 million on June 30, 2007, 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 13, 2008 was
8,170,000.
DOCUMENTS INCORPORATED BY REFERENCE: None
PART I
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains certain forward-looking statements within the meaning of
the federal securities laws. All statements, other than statements of historical fact included in
this Form 10-K, including, but not limited to, those under Business, Risk Factors and
Properties in Items 1, 1A and 2 and Managements Discussion and Analysis of Financial Condition
and Results of Operations in Item 7, are forward-looking statements. These statements are based
on managements belief and assumptions using currently available information and expectations as of
the date hereof, are not guarantees of future performance and involve certain risks and
uncertainties. Although we believe that the expectations reflected in these forward-looking
statements are reasonable, we cannot assure you that our expectations will prove to be correct.
Therefore, actual outcomes and results could differ materially from what is expressed, implied or
forecast in these statements. Any differences could be caused by a number of factors including,
but not limited to:
|
|
|
Risks and uncertainties with respect to the actual quantities of petroleum products
shipped on our pipelines and/or terminalled in our terminals; |
|
|
|
|
The economic viability of Holly Corporation, Alon USA, Inc. and our other customers; |
|
|
|
|
The demand for refined petroleum products in markets we serve; |
|
|
|
|
Our ability to successfully purchase and integrate additional operations in the future; |
|
|
|
|
Our ability to complete previously announced pending or contemplated acquisitions; |
|
|
|
|
The availability and cost of our financing; |
|
|
|
|
The possibility of reductions in production or shutdowns at refineries utilizing our
pipeline and terminal facilities; |
|
|
|
|
The effects of current and future government regulations and policies; |
|
|
|
|
Our operational efficiency in carrying out routine operations and capital construction
projects; |
|
|
|
|
The possibility of terrorist attacks and the consequences of any such attacks; |
|
|
|
|
General economic conditions; and |
|
|
|
|
Other financial, operations and legal risks and uncertainties detailed from time to time
in our Securities and Exchange Commission filings. |
Cautionary statements identifying important factors that could cause actual results to differ
materially from our expectations are set forth in this Form 10-K, including without limitation, in
conjunction with the forward-looking statements included in the Form 10-K that are referred to
above. When considering forward-looking statements, you should keep in mind the risk factors and
other cautionary statements set forth in this Form 10-K under Risk Factors in Item 1A. All
forward-looking statements included in this Form 10-K and all subsequent written or oral
forward-looking statements attributable to us or persons acting on our behalf are expressly
qualified in their entirety by these cautionary statements. The forward-looking statements speak
only as of the date made and, other than as required by law, we undertake no obligation to publicly
update or revise any forward-looking statements, whether as a result of new information, future
events or otherwise.
- 3 -
INDEX TO DEFINED TERMS AND NAMES
The following terms and names that appear in this form 10-K are defined on the following pages:
|
|
|
|
|
Alon |
|
|
5 |
|
Alon PTA |
|
|
5 |
|
Big Spring Refinery |
|
|
5 |
|
BP |
|
|
15 |
|
bpd |
|
|
6 |
|
Credit Agreement |
|
|
50 |
|
Distributable cash flow |
|
|
42 |
|
DOT |
|
|
10 |
|
EBITDA |
|
|
36 |
|
FERC |
|
|
11 |
|
GAAP |
|
|
36 |
|
HEP |
|
|
5 |
|
HLS |
|
|
5 |
|
Holly |
|
|
5 |
|
Holly IPA |
|
|
5 |
|
Holly PTA |
|
|
5 |
|
Intermediate Pipelines |
|
|
5 |
|
Kinder Morgan |
|
|
6 |
|
LIBOR |
|
|
51 |
|
LPG |
|
|
6 |
|
Maintenance capital expenditures |
|
|
36 |
|
mbbls |
|
|
26 |
|
mbpd |
|
|
43 |
|
Mid-America |
|
|
26 |
|
Navajo Refinery |
|
|
5 |
|
NPL |
|
|
5 |
|
NuStar |
|
|
30 |
|
Plains |
|
|
9 |
|
PPI |
|
|
6 |
|
Purchase Agreement |
|
|
8 |
|
Rio Grande |
|
|
5 |
|
SEC |
|
|
5 |
|
Senior Notes |
|
|
7 |
|
SFAS |
|
|
54 |
|
Sinclair |
|
|
31 |
|
South System |
|
|
6 |
|
ULSD |
|
|
43 |
|
UNEV Pipeline |
|
|
9 |
|
Valero |
|
|
30 |
|
Terms used in the financial statements and footnotes are as defined therein.
- 4 -
Item 1. Business
OVERVIEW
Holly Energy Partners, L.P. (HEP) is a Delaware limited partnership formed by Holly
Corporation and is the successor to Navajo Pipeline Co., L.P. (Predecessor) (NPL). We operate a
system of refined product pipelines and distribution terminals primarily in west Texas, New Mexico,
Utah and Arizona. We maintain our principal corporate offices at 100 Crescent Court, Suite 1600,
Dallas, Texas 75201-6915. Our telephone number is 214-871-3555 and our internet website address
is www.hollyenergy.com. The information contained on our website does not constitute part of this
Annual Report on Form 10-K. A copy of this Annual Report on Form 10-K will be provided without
charge upon written request to the Vice President, Investor Relations at the above address. A
direct link to our filings at the U.S. Securities and Exchange Commission (SEC) website is
available on our website on the Investors page. Additionally available on our website are copies
of our Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter,
and Code of Business Conduct and Ethics, all of which will be provided without charge upon written
request to the Vice President, Investor Relations at the above address. In this document, the
words we, our, ours and us refer to HEP and its consolidated subsidiaries or to HEP or an
individual subsidiary and not to any other person. Holly refers to Holly Corporation and its
subsidiaries, other than HEP and its subsidiaries and other than Holly Logistic Services, L.L.C.
(HLS), a subsidiary of Holly Corporation that is the general partner of the general partner of
HEP and manages HEP.
HEP acquired substantially all of the refined product pipeline and terminalling assets that support
Hollys refining and marketing operations in west Texas, New Mexico, Utah and Arizona and a 70%
interest in Rio Grande Pipeline Company (Rio Grande) upon the closing of its initial public
offering in July 2004.
On February 28, 2005, we acquired from Alon USA, Inc. and several of its wholly-owned subsidiaries
(collectively, Alon) four refined products pipelines, an associated tank farm and two refined
products terminals located primarily in Texas. On July 8, 2005, we acquired Hollys two 65-mile
parallel intermediate feedstock pipelines (the Intermediate Pipelines) which connect its
Lovington, New Mexico and Artesia, New Mexico refining facilities (collectively, the Navajo
Refinery).
We generate revenues by charging tariffs for transporting petroleum products through our pipelines
and by charging fees for terminalling refined products and other hydrocarbons, and storing and
providing other services at our terminals. We do not take ownership of products that we transport
or terminal; therefore, we are not directly exposed to changes in commodity prices. We serve
Hollys refineries in New Mexico and Utah under two 15-year pipeline and terminal agreements with
Holly. One of these agreements relates to the pipelines and terminals contributed by Holly to us
at the time of our initial public offering and expires in 2019 (Holly PTA). Our other agreement
with Holly relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in
2020 (Holly IPA). We also serve Alons Big Spring, Texas refinery (Big Spring Refinery) under
the Alon Pipelines and Terminals Agreement expiring 2020 (Alon PTA). The substantial majority of
our business is devoted to providing transportation and terminalling services to Holly. We operate
our business as one business segment. Our assets include:
Pipelines:
|
|
|
approximately 780 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; |
|
|
|
|
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; |
|
|
|
|
two parallel 65-mile pipelines that transport intermediate feedstocks and crude oil from
Hollys Lovington, New Mexico refinery facilities to Hollys Artesia, New Mexico refinery
facilities; and |
- 5 -
|
|
|
a 70% interest in Rio Grande, a joint venture that owns a 249-mile refined product
pipeline that transports liquid petroleum gases (LPG) from west Texas to the Texas/Mexico
border near El Paso for further transport into northern Mexico. |
Refined Product Terminals:
|
|
|
four refined product terminals (one of which is 50% owned), located in El Paso, Texas;
Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of
approximately 900,000 barrels, that are integrated with our refined product pipeline system
that serves Hollys Navajo Refinery; |
|
|
|
|
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; |
|
|
|
|
one refined product terminal near Mountain Home, Idaho with a capacity of 120,000
barrels, that serves a nearby United States Air Force Base; |
|
|
|
|
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; and |
|
|
|
|
two refined product truck loading racks, one located within Hollys Navajo Refinery that
is permitted to load over 40,000 barrels per day (bpd) of light refined products, and one
located within Hollys Woods Cross Refinery near Salt Lake City, Utah, that is permitted to
load over 25,000 bpd of light refined products. |
Agreements with Holly
Under the 15-year Holly PTA, Holly pays us fees to transport on our refined product pipelines or
throughput in our terminals a volume of refined products that will produce a minimum level of
revenue. This minimum revenue commitment will increase each year at a rate equal to the percentage
change in the producer price index (PPI), but will not decrease as a result of a decrease in the
PPI. Following the July 1, 2007 PPI adjustment, the volume commitments by Holly under the Holly
PTA will produce a minimum of $39.6 million of revenue for the twelve months ending June 30, 2008.
Holly pays the published tariff rates on the refined product pipelines and contractually agreed
upon fees at the terminals. The tariffs adjust annually at a rate equal to the percentage change
in the PPI. The terminal fees adjust annually based upon an index comprised of comparable fees
posted by third parties. Hollys minimum revenue commitment applies only to the initial assets we
acquired from Holly and may not be spread among assets we subsequently acquire. If Holly fails to
meet its minimum revenue commitment in any quarter, it is 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
may be applied as a credit in the following four quarters after Hollys minimum obligations are
met.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we
have agreed to expand our refined products pipeline system between Artesia, New Mexico and El Paso,
Texas (the South System). The expansion of the South System will include replacing 85 miles of
8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso
Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan L.P. (Kinder Morgan)
pipeline to Tucson and Phoenix, Arizona, and making related modifications. The cost of this
project is estimated to be $48.3 million. Currently, we are expecting to complete this project by
January 2009. The agreement also provides for a tariff increase, expected to be effective May 1, 2008,
on Holly shipments on our refined product pipelines.
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
- 6 -
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. In such instances, we will negotiate in good faith with Holly to agree on the level
of the monthly surcharge or increased tariff rate.
Hollys obligations under this agreement may be proportionately reduced or suspended if Holly shuts
down or materially reconfigures one of its refineries. Holly will be required to give at least
twelve months advance notice of any long-term shutdown or material reconfiguration. Hollys
obligations may also be temporarily suspended or terminated in certain circumstances.
Under certain provisions of an omnibus agreement that we entered with Holly in July 2004 and
expires in 2019 (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.
Initially, this fee was $2.0 million for each of the three years following the closing of our
initial public offering. Effective July 1, 2007, the annual fee increased to $2.1 million in
accordance with provisions under the agreement. 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 other employees of HLS 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 also agreed to
indemnify us in an aggregate amount not to exceed $15.0 million for ten years after the closing of
our initial public offering for any environmental noncompliance and remediation liabilities
associated with the assets transferred to us and occurring or existing prior to the closing date of
our initial public offering.
Alon Transaction
On February 28, 2005, we acquired from Alon four refined products pipelines, an associated tank
farm and two refined products terminals. These pipelines and terminals are located primarily in
Texas and transport and terminal light refined products for Alons refinery in Big Spring, Texas.
The total consideration paid for these pipeline and terminal assets was $120.0 million in cash and
937,500 of our Class B subordinated units which, subject to certain conditions, will convert into
an equal number of common units on February 28, 2010. We financed the Alon transaction with a
portion of the proceeds of our private offering of $150.0 million principal amount of 6.25% senior
notes due 2015 (the Senior Notes). In connection with the Alon transaction, we entered into the
Alon PTA. Under this agreement, Alon agreed to transport on our pipelines and throughput in our
terminals a volume of refined products that would result in minimum revenue levels each year that
will change annually based on changes in the PPI, but will not decrease below the initial $20.2
million annual amount. Following the March 1, 2007 PPI rate adjustment, Alons total minimum
commitment for the twelve months ending February 29, 2008 is $20.9 million. The agreed upon
tariffs increase or decrease each year at a rate equal to the percentage change in the PPI, but not
below the initial tariffs. Alons minimum volume commitment was calculated based on 90% of Alons
then recent usage of these pipelines and terminals taking into account an expansion of Alons Big
Spring Refinery completed in February 2005. At revenue levels above 105% of the base revenue
amount, as adjusted each year for changes in the PPI, Alon will receive an annual 50% discount on
incremental revenues. Alons obligations under the Alon PTA may be reduced or suspended under
certain circumstances. We granted Alon a second mortgage on the pipelines and terminals acquired
from Alon to secure certain of Alons rights under the Alon PTA. Alon has a right of first refusal
to purchase the pipelines and terminals if we decide to sell them in the future. Additionally, we
entered into an environmental agreement expiring in 2015 with Alon with respect
to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired
from Alon, whereby Alon will indemnify us subject to a $100,000 deductible and a $20.0 million
maximum liability cap.
- 7 -
The consideration for the Alon pipeline and terminal assets was allocated to the individual assets
acquired based on their estimated fair values. Fair values of the assets acquired were estimated
using the cost, market and income approach methodologies. Under the cost approach, management
determined the fair value of acquired tangible pipeline and terminal assets based on the estimated
replacement cost of assets using current costs, adjusted for the effects of physical depreciation
and physical deterioration. The fair value of acquired rights of way was determined using the
market approach based on publicly available market data. The value of the transportation agreement
was determined using the income approach, under which management estimated the net present value of
the after-tax earnings attributable to the Alon PTA over a 30-year life (the 15-year initial term
plus the expected 15 years of extension periods), plus the value of the tax benefit of
amortization.
Holly Intermediate Pipelines Transaction
On July 8, 2005, we acquired pursuant to a definitive purchase agreement (the Purchase Agreement)
Hollys Intermediate Pipelines which connect its Lovington, New Mexico and Artesia, New Mexico
refining facilities. The total consideration was $81.5 million, which consisted of $77.7 million
in cash, 70,000 common units of HEP and a capital account credit of $1.0 million to maintain
Hollys existing general partner interest in the Partnership. We financed the cash portion of the
consideration for the Intermediate Pipelines with the proceeds raised from (a) the private sale of
1,100,000 of our common units for $45.1 million to a limited number of institutional investors
which closed simultaneously with the acquisition and (b) an additional $35.0 million in principal
amount of our 6.25% senior notes due 2015. This acquisition was made pursuant to an option to
purchase these pipelines granted by Holly to us at the time of our initial public offering in July
2004.
In connection with this transaction, we entered into an agreement with Holly to transport volumes
of intermediate products on the Intermediate Pipelines that expires in 2020. Under the Holly IPA,
Holly agreed to transport volumes of product that would result in initial minimum funds to us of
$11.8 million each year that will change annually based on changes in the PPI but will not decrease
as a result of a decrease in the PPI. Following the July 1, 2007 PPI adjustment, the volume
commitments by Holly under the Holly IPA will result in minimum funds to us of $12.8 million for
the twelve months ending June 30, 2008. Hollys minimum revenue commitment applies only to the
Intermediate Pipelines, and Holly is not able to spread its minimum revenue commitment among
pipeline assets HEP already owns or subsequently acquires. If Holly fails to meet its minimum
revenue commitment in any quarter, it is 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 may be applied as
a credit in the following four quarters after Hollys minimum obligations are met. The Holly IPA
may be extended by the mutual agreement of the parties.
If new laws or regulations are enacted that require us to make substantial and unanticipated
capital expenditures with regard to the Intermediate Pipelines, we have the right to amend the
tariff rates to recover our costs of complying with these new laws or regulations (including a
reasonable rate of return). Under certain circumstances, either party may temporarily suspend its
obligations under the Holly IPA. We granted Holly a second mortgage on the Intermediate Pipelines
to secure certain of Hollys rights under the Holly IPA. Holly agreed to provide $2.5 million of
additional indemnification above the initial $15.0 million of indemnification under the Omnibus
Agreement that previously provided for environmental noncompliance and remediation liabilities
occurring or existing before the closing date of the Purchase Agreement, bringing the total
indemnification, expiring in 2020, provided to us from Holly to $17.5 million. Of this total,
indemnification above $15.0 million relates solely to the Intermediate Pipelines.
As this transaction was among entities under common control, we recorded the acquired assets at
Hollys historic book value of $6.8 million. The $71.9 million excess of the purchase price over
the historic book value is recorded as a reduction to partners equity for financial accounting
purposes.
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
- 8 -
capital requirements have consisted of, and are expected to continue to consist
of, maintenance capital expenditures and expansion capital expenditures. Maintenance capital
expenditures represent capital expenditures to replace partially or fully depreciated assets to
maintain the operating capacity of existing assets. Maintenance capital expenditures include
expenditures required to maintain equipment reliability, tankage and pipeline integrity, and safety
and to address environmental regulations. Expansion capital expenditures represent capital
expenditures to expand the operating capacity of existing or new assets, whether through
construction or acquisition. Expansion capital expenditures include expenditures to acquire assets
to grow our business and to expand existing facilities, such as projects that increase throughput
capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with
existing assets that are minor in nature and do not extend the useful life of existing assets are
charged to operating expenses as incurred.
Each year the HLS board of directors approves our annual capital budget, which specifies capital
projects that our management is authorized to undertake. Additionally, at times when conditions
warrant or as new opportunities arise, special projects may be approved. The funds allocated to a
particular capital project may be expended over a period in excess of a year, depending on the time
required to complete 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.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we
have agreed to expand our South System between Artesia, New Mexico and El Paso, Texas. The
expansion of the South System will include replacing 85 miles of 8-inch pipe with 12-inch pipe,
adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing
pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making
related modifications. The cost of this project is estimated to be $48.3 million. Currently, we
are expecting to complete this project by January 2009. The agreement also provides for a tariff
increase, expected to be effective May 1, 2008, on Holly shipments on our refined product
pipelines.
In November 2007, we announced an agreement in principle for the acquisition of certain
pipeline and tankage assets from Holly for approximately $180.0 million. The consideration is
expected to consist of $171.0 million in cash and our common units valued at approximately $9.0
million. The assets include 136 miles of crude oil trunk lines that deliver crude to Hollys
Navajo Refinery in southeast New Mexico, approximately 725 miles of gathering and connection
pipelines located in west Texas and New Mexico, on-site crude tankage having a combined 600,000
barrels of storage capacity located within the Navajo and Woods Cross refinery complexes, a jet
fuel products pipeline and terminal (terminal leased through September 2011) between Artesia and
Roswell, New Mexico, and 10 miles of crude oil and product pipelines that support Hollys Woods
Cross Refinery. In connection with the closing of this proposed transaction, we intend to enter
into a 15-year pipelines and tankage agreement with Holly that will contain a minimum annual
revenue commitment to us from Holly. Both the HLS and Holly boards of directors have approved this
proposed transaction, which we expect to close in the first quarter of 2008.
In November 2007, we executed a definitive agreement with Plains All American Pipeline, L.P.
(Plains) to acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system now
under construction by Plains, for the shipment of up to 120,000 bpd of crude oil into the Salt Lake
City area (the SLC Pipeline). Under the agreement, the SLC Pipeline will be owned by a joint
venture company which will be owned 75% by Plains and 25% by us. Subject to the actual cost of the
SLC Pipeline, we will purchase our 25% interest in the joint venture for an amount between $22.0
and $25.5 million in the second quarter of 2008, when the SLC Pipeline is expected to become fully
operational. The SLC Pipeline will allow various refiners in the Salt Lake City area, including
Hollys Woods Cross refinery, to ship crude oil into the Salt Lake City area from the Utah terminus
of the Frontier Pipeline as well as crude oil from Wyoming and Utah, which is currently flowing on
Plains Rocky Mountain Pipeline.
- 9 -
On January 31, 2008, we entered
into an option agreement with Holly, granting us an option to purchase all of Hollys equity
interests in a joint venture pipeline currently under construction. The pipeline will be
capable of transporting refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada (the UNEV Pipeline). Holly currently owns 75% of the equity interests in the
UNEV Pipeline. Under this agreement, we have an option to
purchase Hollys equity interests in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Hollys investment in the joint venture pipeline, plus interest at 7% per annum.
The initial capacity of the pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total cost of the pipeline project
including terminals is expected to be $300.0 million. Hollys share of this cost is $225.0
million. Construction of this project is currently expected to be completed and operational in mid
2009.
We are also studying several other projects, which are in various stages of analysis.
We expect that our currently planned expenditures for sustaining and maintenance capital as well as
expenditures for capital development projects such as the UNEV Pipeline, SLC Pipeline and South
System expansion projects described above will be funded with existing cash balances, cash
generated by operations, the sale of additional limited partner units and advances under our $100
million senior secured revolving credit agreement maturing August 2011 (the Credit Agreement).
Additionally, we plan to upsize our Credit Agreement to fund the cash portion of the consideration
for our announced purchase of certain pipeline and tankage assets from Holly described above.
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.
We started our smart pigging program in 1988, prior to Department of Transportation (DOT)
regulations requiring the program. Beginning in 2002, the DOT required smart pigging or other
integrity testing of all DOT-regulated crude oil and refined product pipelines. This requirement
is being phased in over a five-year period. As of December 31, 2007 we were in compliance with DOT
requirements.
Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response
personnel are located along the pipelines. Employees participate in simulated spill deployment
exercises on a regular basis. They also participate in actual spill response boom deployment
exercises in planned spill scenarios in accordance with Oil Pollution Act of 1990 requirements. We
believe that all of our pipelines have been constructed and are maintained in all material respects
in accordance with applicable federal, state, and local laws and the regulations and standards
prescribed by the American Petroleum Institute, the DOT, and accepted industry practice.
At our terminals, tanks designed for gasoline storage are equipped with internal or external
floating roofs that minimize emissions and prevent potentially flammable vapor accumulation between
fluid levels and
the roof of the tank. Our terminal facilities have facility response plans, spill prevention and
control plans, and other plans and programs to respond to emergencies.
Many of our terminal loading racks are protected with water deluge systems activated by either heat
sensors or an emergency switch. Several of our terminals are also protected by foam systems that
are
- 10 -
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 Refinery, our contractual relationship
with Holly under the Omnibus Agreement and the two Holly pipelines and terminals agreements, we
believe that we will not face significant competition for barrels of refined products transported
from Hollys Navajo Refinery, particularly during the term of our Holly PTA and Holly IPA expiring
in 2019 and 2020, respectively. Additionally, with our contractual relationship with Alon under
the Alon PTA, we believe that we will not face significant competition for those barrels of refined
products we transport from Alons Big Spring Refinery, particularly during the term of our Alon PTA
expiring in 2020.
However, we do face competition from other pipelines that may be able to supply the end-user
markets of Holly or Alon with refined products on a more competitive basis. Additionally, If
Hollys wholesale customers reduced their purchases of refined products due to the increased
availability of cheaper product from other suppliers or for other reasons, the volumes transported
through our pipelines could be reduced, which, subject to the minimum revenue commitments, could
cause a decrease in cash and revenues generated from our operations.
The petroleum refining business is highly competitive. Among Hollys competitors are some of the
worlds largest integrated petroleum companies, which have their own crude oil supplies and
distribution and marketing systems. Holly competes with independent refiners as well. Competition
in particular geographic areas is affected primarily by the amounts of refined products produced by
refineries located in such areas and by the availability of refined products and the cost of
transportation to such areas from refineries located outside those areas.
In addition, we face competition from trucks that deliver product in a number of areas we serve.
Although their costs may not be competitive for longer hauls or large volume shipments, trucks
compete effectively for incremental and marginal volumes in many areas we serve. The availability
of truck transportation places some competitive constraints on us.
Historically, the significant majority of the throughput at our terminal facilities has come from
Holly, with the exception of third-party receipts at the Spokane terminal, Alon volumes at El Paso,
and the Abilene and Wichita Falls terminals that serve Alons Big Springs Refinery. Under the
terms of the Holly PTA, we continue to receive a significant portion of the throughput at our
terminal facilities from Holly.
Our ten refined product terminals compete with other independent terminal operators as well as
integrated oil companies on the basis of terminal location, price, versatility and services
provided. Our competition primarily comes from integrated petroleum companies, refining and
marketing companies, independent terminal companies and distribution companies with marketing and
trading arms.
RATE REGULATION
Some of our existing pipelines are subject to rate regulation by the Federal Energy Regulatory
Commission (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 proposed new or changed rates by protest, and challenges to rates that are already on
file and in effect by complaint. Upon the appropriate showing, a successful complainant may obtain
damages or reparations for generally up to two years prior to the filing of a complaint. The FERC
generally has not investigated interstate rates on its own initiative when those rates, like ours,
have not been the subject of a protest or a complaint by a shipper. However, the FERC could
investigate any new interstate rates we might file if those rates were protested by a third party
and the third party were able to show that it had a substantial economic interest in our tariff
rate level. The FERC could also investigate any of our existing interstate rates if a complaint
were filed against the rate.
- 11 -
While the FERC regulates the rates for interstate shipments on our refined product pipelines, the
New Mexico Public Regulation Commission regulates the rates for intrastate shipments in New Mexico,
the Texas Railroad Commission regulates the rates for intrastate shipments in Texas, and the Idaho
Public Utilities Commission regulates the rates for intrastate shipments in Idaho. State
commissions have generally not been aggressive in regulating common carrier pipelines and have
generally not investigated the rates or practices of petroleum pipelines in the absence of shipper
complaints, and we do not believe the intrastate tariffs now in effect are likely to be challenged.
However, a state regulatory commission could investigate our rates if such a challenge were filed.
ENVIRONMENTAL REGULATION AND REMEDIATION
Our operation of pipelines, terminals, and associated facilities in connection with the storage and
transportation of refined products is subject to stringent and complex federal, state, and local
laws and regulations governing the discharge of materials into the environment, or otherwise
relating to the protection of the environment. As with the industry generally, compliance with
existing and anticipated laws and regulations increases our overall cost of business, including our
capital costs to construct, maintain, and upgrade equipment and facilities. Although these laws
and regulations affect our maintenance capital expenditures and net income, we believe that they do
not affect our competitive position in that the operations of our competitors are similarly
affected. We believe that our operations are in substantial compliance with applicable
environmental laws and regulations. However, these laws and regulations, and the interpretation or
enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to
predict the ongoing cost to us of complying with these laws and regulations or the future impact of
these laws and regulations on our operations. Violation of environmental laws, regulations, and
permits can result in the imposition of significant administrative, civil and criminal penalties,
injunctions, and construction bans or delays. A discharge of hydrocarbons or hazardous substances
into the environment could, to the extent the event is not insured, subject us to substantial
expense, including both the cost to comply with applicable laws and regulations and claims made by
employees, neighboring landowners and other third parties for personal injury and property damage.
We inspect our pipelines regularly using equipment rented from third-party suppliers. Third
parties also assist us in interpreting the results of the inspections.
Holly agreed to indemnify us in an aggregate amount not to exceed $15.0 million for ten years after
the closing of our initial public offering on July 13, 2004 for environmental noncompliance and
remediation liabilities associated with the assets initially transferred to us and occurring or
existing before that date. When the Intermediate Pipelines were purchased in July 2005, Holly
agreed to provide $2.5 million of additional indemnification, bringing the total indemnification
provided to us from Holly to $17.5 million. Of this total, indemnification above $15.0 million
relates solely to the Intermediate Pipelines. Additionally, we entered into an environmental
agreement with Alon with respect to pre-closing environmental costs and liabilities relating to the
pipelines and terminals acquired from Alon, under which Alon, for a ten year term expiring in 2015,
will indemnify us subject to a $100,000 deductible and a $20.0 million maximum liability cap.
Contamination resulting from spills of refined products and crude oil is not unusual within the
petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a
result of past operations have resulted in contamination of the environment, including soils and
groundwater. Site conditions, including soils and groundwater, are being evaluated at a few of our
properties where operations may have resulted in releases of hydrocarbons and other wastes, none of
which we believe will have a significant effect on our operations since the remediation of such
releases would be covered under environmental indemnification agreements.
An environmental remediation project is in progress currently at our El Paso terminal, the
remaining costs of which are projected to be $2.0 million over the next four years. Other parties
are undertaking remediation projects at our Boise, Burley and Albuquerque terminals, and we are
obligated to pay a portion of these costs at the Albuquerque terminal, but not at the Boise or
Burley terminals. As of
- 12 -
December 31, 2007, we estimate the total remaining remediation cost for
the Albuquerque terminal to be insignificant. A remediation project is also under way in New
Mexico concerning a leak at a point along our refined product pipeline from Artesia, New Mexico to
Orla, Texas. As of At December 31, 2007, we estimate the remaining cost on this project to be $0.3
million, half of which will be incurred in 2008. Holly has agreed, subject to a $15.0 million
limit, to indemnify us for environmental liabilities related to the assets transferred to us by
Holly to the extent such liabilities existed or arose from operation of these assets prior to the
closing of our initial public offering on July 13, 2004 and are asserted within 10 years after that
date. The Holly indemnification will cover the costs associated with the remediation projects
mentioned above, including assessment, monitoring, and remediation programs.
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 106 people who provide direct support to our operations,
of which 6 are covered by collective bargaining agreements that expire in March 2009. Holly
Logistic Services, L.L.C. considers its employee relations to be good. Neither we nor our general
partner have employees. We reimburse Holly for direct expenses that Holly or its affiliates incurs
on our behalf for the employees of HLS.
Item 1A. Risk Factors
Investing in us involves a degree of risk, including the risks described below. You should
carefully consider the following risk factors together with all of the other information included
in this Annual Report on Form 10-K, including the financial statements and related notes, when
deciding to invest in us. Additional risks and uncertainties not currently known to us or that we
currently deem to be immaterial may also materially and adversely affect our business operations.
If any of the following risks were to actually occur, our business, financial condition, results
of operations or treatment of unitholders could be materially and adversely affected.
We depend upon Holly and particularly its Navajo Refinery for a majority of our revenues; if those
revenues were 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, 2007, Holly accounted for 58% of the revenues of our petroleum
products pipelines and 67% of the revenues of our terminals and truck loading racks. We expect to
continue to derive a majority of our revenues from Holly for the foreseeable future. If Holly
satisfies only its minimum obligations under the Holly PTA and Holly IPA or is unable to meet its
minimum revenue commitment for any reason, including due to prolonged downtime or a shutdown at the
Navajo Refinery or the Woods Cross Refinery, our revenues would decline.
Any significant curtailing of production at the Navajo Refinery could, by reducing throughput in
our pipelines and terminals, result in our realizing materially lower levels of revenues and cash
flow for the duration of the shutdown. For the year ended December 31, 2007, production from the
Navajo Refinery accounted for 55% of the throughput volumes transported by our refined product
pipelines. The Navajo Refinery also received 100% of the petroleum products shipped on our
Intermediate Pipelines. Operations at the Navajo Refinery could be partially or completely shut
down, temporarily or permanently,
as the result of:
|
|
|
competition from other refineries and pipelines that may be able to supply the
refinerys end-user markets on a more cost-effective basis; |
- 13 -
|
|
|
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; |
|
|
|
|
planned maintenance or capital projects; |
|
|
|
|
increasingly stringent environmental laws and regulations, such as the Environmental
Protection Agencys gasoline and diesel sulfur control requirements that limit the
concentration of sulfur in motor gasoline and diesel fuel for both on-road and non-road
usage as well as various state and federal emission requirements that may affect the
refinery itself; |
|
|
|
|
an inability to obtain crude oil for the refinery at competitive prices; or |
|
|
|
|
a general reduction in demand for refined products in the area due to: |
|
- |
|
a local or national recession or other adverse economic condition that results
in lower spending by businesses and consumers on gasoline and diesel fuel; |
|
|
- |
|
higher gasoline prices due to higher crude oil prices, higher taxes or stricter
environmental laws or regulations; or |
|
|
- |
|
a shift by consumers to more fuel-efficient or alternative fuel vehicles or an
increase in fuel economy, whether as a result of technological advances by
manufacturers, legislation either mandating or encouraging higher fuel economy or the
use of alternative fuel or otherwise. |
The magnitude of the effect on us of any shutdown would depend on the length of the shutdown and
the extent of the refinery operations affected by the shutdown. We have no control over the
factors that may lead to a shutdown or the measures Holly may take in response to a shutdown.
Holly makes all decisions at the Navajo Refinery concerning levels of production, regulatory
compliance, refinery turnarounds (planned shutdowns of individual process units within the refinery
to perform major maintenance activities), labor relations, environmental remediation and capital
expenditures; is responsible for all related costs; and is under no contractual obligation to us to
maintain operations at the Navajo Refinery.
Furthermore, Hollys obligations under the Holly PTA and Holly IPA would be temporarily suspended
during the occurrence of a force majeure that renders performance impossible with respect to an
asset for at least 30 days. If such an event were to continue for a year, we or Holly could
terminate the agreements. The occurrence of any of these events could reduce our revenues and cash
flows.
We depend on Alon and particularly its Big Spring Refinery for a substantial portion of our
revenues; if those revenues were significantly reduced, there would be a material adverse effect on
our results of operations.
For the year ended December 31, 2007, Alon accounted for 27% of the combined revenues of our
petroleum products 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. As a result, our revenues would be materially
adversely affected. The Big Spring Refinery could partially or completely shut down its
operations, temporarily or permanently, due to factors affecting its ability to produce refined
products or for planned maintenance or capital projects. Such factors would include the factors
discussed above under the discussion of risk factors for the Navajo Refinery.
The magnitude of the effect on us of any shutdown would depend 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
- 14 -
responsible for all costs at the Big Spring Refinery concerning levels of production,
regulatory compliance, refinery turnarounds, labor relations, environmental remediation and capital
expenditures.
In addition, under the Alon PTA, if we are unable to transport or terminal refined products that
Alon is prepared to ship, then Alon has the right to reduce its minimum volume commitment to us
during the period of interruption. If a force majeure event occurs beyond the control of either of
us, we or Alon could terminate the Alon pipelines and terminals agreement after the expiration of
certain time periods. The occurrence of any of these events could reduce our revenues and cash
flows.
We are exposed to the credit risks of our key customers.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. As
stated above, we receive substantial revenues from both Holly and Alon under their respective
pipelines and terminals agreements. In addition, a subsidiary of BP Plc (BP) is the only shipper
on the Rio Grande Pipeline, a joint venture in which we own a 70% interest and from which we
derived 9% of our revenues for the year ended December 31, 2007.
If any of our key customers default on their obligations to us, our financial results could be
adversely affected. Furthermore, some of our customers may be highly leveraged and subject to
their own operating and regulatory risks.
Competition from other pipelines that may be able to supply our shippers customers with refined
products at a lower price could cause us to reduce our rates or could reduce our revenues.
We and our shippers could face increased competition if other pipelines are able to competitively
supply our shippers end-user markets with refined products. The Longhorn Pipeline is a 72,000 bpd
common carrier pipeline that delivers refined products utilizing a direct route from the Texas Gulf
Coast to El Paso and, through interconnections with third-party common carrier pipelines, into the
Arizona market. Deliveries of refined products shipped
on the Longhorn Pipeline increased significantly during 2007, and we believe is currently operating
at or near full capacity. Longhorn Partners Pipeline, L.P., owner of the Longhorn Pipeline, has
also announced a planned expansion of its pipeline from 72,000 bpd to 125,000 bpd. Also in 2007,
Kinder Morgan completed an expansion of its El Paso, Texas to Tucson and Phoenix, Arizona
pipeline, increasing its capacity to 200,000 bpd. 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. Such eventuality 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, could materially reduce our revenues.
The volume of refined products we transport in our refined products pipelines depends on the level
of production of refined products from Hollys and Alons refineries, which, in turn, depends on
the availability of attractively-priced crude oil produced in the areas accessible to those
refineries. In order to maintain or
- 15 -
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, 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.
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 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.
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
ranging from four to twelve years. BPs agreement to ship on the Rio Grande Pipeline expires in
April 2008. Our pipelines and terminals agreements with Holly and Alon expire in 2019 and 2020,
respectively.
Our operations are subject to federal, state, and local laws and regulations relating to
environmental protection and operational safety that could require us to make substantial
expenditures.
Our pipelines and terminal operations are subject to increasingly strict environmental and safety
laws and regulations. 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.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not
be adequately insured.
Our operations are subject to operational hazards and unforeseen interruptions such as natural
disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical
failures and other events beyond our control. These events might result in a loss of equipment or
life, injury, or extensive property damage, as well as an interruption in our operations. We may
not be able to maintain
or obtain insurance of the type and amount we desire at reasonable rates. 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
- 16 -
coverage. If we were to incur a significant liability for which we were not fully insured, it
could have a material adverse effect on our financial position.
Any reduction in the capacity of, or the allocations to, our shippers on interconnecting,
third-party pipelines could cause a reduction of volumes transported in our pipelines and through
our terminals.
Holly, Alon and the other users of our pipelines and terminals are dependent upon connections to
third-party pipelines to receive and deliver crude oil and refined products. Any reduction of
capacities of these interconnecting pipelines due to testing, line repair, reduced operating
pressures, or other causes could result in reduced volumes transported in our pipelines or through
our terminals. Similarly, if additional shippers begin transporting volumes of refined products
over interconnecting pipelines, the allocations to existing shippers in these pipelines would be
reduced, which could also reduce volumes transported in our pipelines or through our terminals.
For example, the common carrier pipelines used by Holly to serve the Arizona and Albuquerque
markets are currently operated at or near capacity and are subject to proration. As a result, the
volumes of refined product that Holly and other shippers have been able to deliver to these markets
have been limited. The flow of additional products into El Paso for shipment to Arizona could
further exacerbate such constraints on deliveries to Arizona. Any reduction in volumes transported
in our pipelines or through our terminals could adversely affect our revenues and cash flows.
If our assumptions concerning population growth are inaccurate or if Hollys growth strategy is not
successful, our ability to grow may be adversely affected.
Our growth strategy is dependent upon:
|
|
|
the accuracy of our assumption that many of the markets that we currently serve or have
plans to serve in the Southwestern and Rocky Mountain regions of the United States will
experience population growth that is higher than the national average; and |
|
|
|
|
the willingness and ability of Holly to capture a share of this additional demand in its
existing markets and to identify and penetrate new markets in the Southwestern and Rocky
Mountain regions of the United States. |
If our assumptions about growth in market demand prove incorrect, Holly may not have any incentive
to increase refinery capacity and production or shift additional throughput to our pipelines, which
would adversely affect our growth strategy. Furthermore, Holly is under no obligation to pursue a
growth strategy. If Holly chooses not to gain, or is unable to gain additional customers in new or
existing markets in the Southwestern and Rocky Mountain regions of the United States, our growth
strategy would be adversely affected. Moreover, Holly may not make acquisitions that would provide
acquisition opportunities to us; or, if those opportunities arise, they may not be on terms
attractive to us. Finally, Holly also will be subject to integration risks with respect to any new
acquisitions it chooses to make.
Growing our business by constructing new pipelines and terminals, or expanding existing ones,
subjects us to construction risks.
One of the ways we may grow our business is through the construction of new pipelines and terminals
or the expansion of existing ones. The construction of a new pipeline or the expansion of an
existing pipeline, by adding horsepower or pump stations or by adding a second pipeline along an
existing pipeline, involves numerous regulatory, environmental, political, and legal uncertainties,
most of which are beyond our control. These projects may not be completed on schedule or at all or
at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure
of funds on a particular project. For instance, if we build a new pipeline, the construction will
occur over an extended period of time and we will not receive any material increases in revenues
until after completion of the project. Moreover, we may construct facilities to capture
anticipated future growth in demand for refined products
in a region in which such growth does not materialize. As a result, new facilities may not be able
to attract enough throughput to achieve our expected investment return, which could adversely
affect our results of operations and financial condition.
- 17 -
Rate regulation may not allow us to recover the full amount of increases in our costs.
The primary rate-making methodology of the FERC is price indexing. We use this methodology in all
of our interstate markets. The indexing method allows a pipeline to increase its rates based on a
percentage change in the producer price index for finished goods. If the index falls, we will be
required to reduce our rates that are based on the FERCs price indexing methodology if they exceed
the new maximum allowable rate. In addition, changes in the index might not be large enough to
fully reflect actual increases in our costs. The FERCs rate-making methodologies may limit our
ability to set rates based on our true costs or may delay the use of rates that reflect increased
costs. Any of the foregoing would adversely affect our revenues and cash flow.
If our interstate or intrastate tariff rates are successfully challenged, we could be required to
reduce our tariff rates, which would reduce our revenues.
Under the FERC indexing methodology, 18 CFR 342-3, our interstate pipeline tariff rates are deemed
just and reasonable. If a party with an economic interest were to file either a protest or a
complaint against our tariff rates, then our existing rates could be subject to detailed review.
If our rates were found to be in excess of levels justified by our cost of service, the FERC could
order us to reduce our rates. 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 would result in lower revenues and cash flows.
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.
If the FERCs petroleum pipeline rate-making methodology changes, the new methodology could result
in tariffs that generate lower revenues and cash flow.
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.
- 18 -
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, 2007, the principal amount of our total outstanding long-term debt was $185.0
million. Various limitations in our Credit Agreement and the indenture for our Senior Notes may
reduce our ability to incur additional debt, to engage in some transactions and to capitalize on
business opportunities. Any subsequent refinancing of our current indebtedness or any new
indebtedness could have similar or greater restrictions.
Our leverage could have important consequences. We will require substantial cash flow to meet our
payment obligations with respect to our indebtedness. Our ability to make scheduled payments, to
refinance our obligations with respect to our indebtedness or our ability to obtain additional
financing in the future will depend on our financial and operating performance, which, in turn, is
subject to prevailing economic conditions and to financial, business and other factors. We believe
that we will have sufficient cash flow from operations and available borrowings under our Credit
Agreement to service our indebtedness. However, a significant downturn in our business or other
development adversely affecting our cash flow could materially impair our ability to service our
indebtedness. If our cash flow and capital resources are insufficient to fund our debt service
obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot
assure you that we would be able to refinance our existing indebtedness or sell assets on terms
that are commercially reasonable.
The instruments governing our debt contain restrictive covenants that may prevent us from engaging
in certain beneficial transactions. The agreements governing our debt generally require us to
comply with various affirmative and negative covenants including the maintenance of certain
financial ratios and restrictions on incurring additional debt, entering into mergers,
consolidations and sales of assets, making investments and granting liens. Additionally, our
contribution agreements with Alon and with Holly with respect to the Intermediate Pipelines
restrict us from selling the pipelines and terminals acquired from Alon or Holly, as applicable,
and from prepaying more than $30.0 million of the Senior Notes until 2015, 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 acquisition, 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.
Our growth through acquisitions may be limited by future market considerations.
Future business or asset acquisitions may be dependent upon financial market conditions. Increases
in our average cost of capital resulting from increases in interest rates or changes in our bond
rating or from increased cost of equity capital may prevent us from making accretive acquisitions
and thus limit our growth opportunities.
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 43% limited partner interest
in us and owns and controls our general partner, HEP Logistics Holdings, L.P. Conflicts of interest
may arise between Holly and its affiliates, including our general partner, on the one hand, and us,
on the other hand. As a result of these conflicts, the general partner may favor its own interests
and the interests of its affiliates over our interests. These conflicts include, among others, the
following situations:
- 19 -
|
|
|
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; |
|
|
|
|
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; |
|
|
|
|
our general partner is allowed to take into account the interests of parties other than
us, such as Holly, in resolving conflicts of interest; |
|
|
|
|
our general partner determines which costs incurred by Holly and its affiliates are
reimbursable by us; |
|
|
|
|
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; |
|
|
|
|
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 |
|
|
|
|
our general partner controls the enforcement of obligations owed to us by our general
partner and its affiliates, including the pipelines and terminals agreement with Holly. |
Cost reimbursements, which will be determined by our general partner, and fees due our general
partner and its affiliates for services provided, are substantial.
Under our partnership agreement, we are currently obligated to pay Holly an administrative fee of
$2.1 million per year for the provision by Holly or its affiliates of various general and
administrative services for our benefit. The administrative fee may increase if we make an
acquisition that requires an increase in the level of general and administrative services that we
receive from Holly or its affiliates. Our general partner will determine the amount of general and
administrative expenses that will be properly allocated to us in accordance with the terms of our
partnership agreement. In addition, our general partner and its affiliates are entitled to
reimbursement for all other expenses they incur on our behalf, including the salaries of and the
cost of employee benefits for employees of Holly Logistic Services, L.L.C. who provide services to
us. Prior to making any distribution on the common units, we will reimburse our general partner and
its affiliates, including officers and directors of the general partner, for all expenses incurred
on our behalf. 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.
- 20 -
The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single
class is required to remove the general partner. Unitholders will be unable to remove the general
partner without its consent because the general partner and its affiliates own sufficient units to
prevent its removal. Also,
if the general partner is removed without cause during the subordination period and units held by
the general partner and its affiliates are not voted in favor of that removal, all remaining
subordinated units will automatically convert into common units and any existing arrearages on the
common units will be extinguished. A removal of the general partner under these circumstances would
adversely affect the common units by prematurely eliminating their distribution and liquidation
preference over the subordinated units, which would otherwise have continued until we had met
certain distribution and performance tests. Cause is narrowly defined to mean that a court of
competent jurisdiction has entered a final, non-appealable judgment finding the general partner
liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our
general partner. Cause does not include most cases of charges of poor management of the business,
so the removal of the general partner because of the unitholders dissatisfaction with the general
partners performance in managing our partnership will most likely result in the termination of the
subordination period.
Furthermore, unitholders voting rights are further restricted by the partnership agreement
provision providing that any units held by a person that owns 20% or more of any class of units
then outstanding, other than the general partner, its affiliates, their transferees, and persons
who acquired such units with the prior approval of the board of directors of the general partners
general partner, cannot vote on any matter. Our partnership agreement also contains provisions
limiting the ability of unitholders to call meetings or to acquire information about our
operations, as well as other provisions limiting the unitholders ability to influence the manner
or direction of management.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a
sale of all or substantially all of its assets without the consent of the unitholders. Furthermore,
our partnership agreement does not restrict the ability of the partners of our general partner from
transferring their respective partnership interests in our general partner to a third party. The
new partners of our general partner would then be in a position to replace the board of directors
and officers of the general partner of our general partner with their own choices and to control
the decisions taken by the board of directors and officers.
We may issue additional common units without unitholder approval, which would dilute an existing
unitholders ownership interests.
During the subordination period, our general partner, without the approval of our unitholders, may
cause us to issue up to 3,500,000 additional common units. Our general partner may also cause us to
issue an unlimited number of additional common units or other equity securities of equal rank with
the common units, without unitholder approval, in a number of circumstances such as:
|
|
|
the issuance of common units in connection with acquisitions or capital improvements
that increase cash flow from operations per unit on an estimated pro forma basis; |
|
|
|
|
issuances of common units to repay indebtedness, the cost of which to service is greater
than the distribution obligations associated with the units issued in connection with the
repayment of the indebtedness; |
|
|
|
|
the conversion of subordinated units into common units; |
|
|
|
|
the conversion of units of equal rank with the common units into common units under some
circumstances; |
|
|
|
|
in the event of a combination or subdivision of common units;
|
- 21 -
|
|
|
issuances of common units under our employee benefit plans; or |
|
|
|
|
the conversion of the general partner interest and the incentive distribution rights
into common units as a result of the withdrawal or removal of our general partner. |
The issuance by us of additional common units or other equity securities of equal or senior rank
will have the following effects:
|
|
|
our unitholders proportionate ownership interest in us will decrease; |
|
|
|
|
the amount of cash available for distribution on each unit may decrease; |
|
|
|
|
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; |
|
|
|
|
the relative voting strength of each previously outstanding unit may be diminished; and |
|
|
|
|
the market price of the common units may decline. |
After the end of the subordination period, we may issue an unlimited number of limited partner
interests of any type without the approval of our unitholders. Our partnership agreement does not
give our unitholders the right to approve our issuance of equity securities ranking junior to the
common units at any time.
In establishing cash reserves, our general partner may reduce the amount of cash available for
distribution to unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash
reserves that it establishes are necessary to fund our future operating expenditures. In addition,
our partnership agreement permits our general partner to reduce available cash by establishing cash
reserves for the proper conduct of our business, to comply with applicable law or agreements to
which we are a party, or to provide funds for future distributions to partners. These cash reserves
will affect the amount of cash available to make the required payments to our debt holders or to
pay the minimum quarterly distribution on our common units every quarter.
Holly and its affiliates may engage in limited competition with us.
Holly and its affiliates may engage in limited competition with us. Pursuant to the omnibus
agreement among us, Holly and our general partner, Holly and its affiliates agreed not to engage in
the business of operating intermediate or refined product pipelines or terminals, crude oil
pipelines or terminals, truck racks or crude oil gathering systems in the continental United
States. The omnibus agreement, however, does not apply to:
|
|
|
any business operated by Holly or any of its subsidiaries at the closing of our initial
public offering; |
|
|
|
|
any crude oil pipeline or gathering system acquired or constructed by Holly or any of
its subsidiaries that is physically interconnected to Hollys refining facilities; |
|
|
|
|
any business or asset that Holly or any of it subsidiaries acquires or constructs that
has a fair market value or construction cost of less than $5.0 million; and |
|
|
|
|
any business or asset that Holly or any of its subsidiaries acquires or constructs that
has a fair market value or construction cost of $5.0 million or more if we have been
offered the opportunity to purchase the business or asset at fair market value, and we
decline to do so with the concurrence of our conflicts committee. |
- 22 -
In the event that Holly or its affiliates no longer control our partnership or there is a change of
control of Holly, the non-competition provisions of the omnibus agreement will terminate.
Our general partner may cause us to borrow funds in order to make cash distributions, even where
the purpose or effect of the borrowing benefits our general partner or its affiliates.
In some instances, our general partner may cause us to borrow funds from affiliates of Holly or
from third parties in order to permit the payment of cash distributions.
These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to
make a distribution on the subordinated units, to make incentive distributions, or to hasten the
expiration of the subordination period.
Our general partner has a limited call right that may require a holder of units to sell its common
units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our
general partner will have the right, but not the obligation, which it may assign to any of its
affiliates or to us, to acquire all, but not less than all, of the common units held by
unaffiliated persons at a price not less than their then-current market price. As a result, a
holder of common units may be required to sell its units at an undesirable time or price and may
not receive any return on its investment. A common unitholder may also incur a tax liability upon a
sale of its units.
A unitholder may not have limited liability if a court finds that unitholder actions constitute
control of our business.
Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a
general partner if a court determined that the right of unitholders to remove our general partner
or to take other action under our partnership agreement constituted participation in the control
of our business.
Our general partner generally has unlimited liability for our obligations, such as our debts and
environmental liabilities, except for those contractual obligations that are expressly made without
recourse to our general partner.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the Delaware
Act) provides that under some circumstances, a unitholder may be liable to us for the amount of a
distribution for a period of three years from the date of the distribution.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well
as our not being subject to entity-level taxation by states. If the IRS were to treat us as a
corporation or if we were to become subject to entity-level taxation for state tax purposes, then
our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax benefit of an investment in the common units depends largely on our being
treated as a partnership for federal income tax purposes. We have not requested, and do not plan to
request, a ruling from the IRS on this or any other matter affecting us.
If we were treated as a corporation for federal income tax purposes, we would pay federal income
tax on our income at the current maximum corporate tax rate of 35%. Distributions to unitholders
would generally be taxed again as corporate distributions, and no income, gains, losses, deductions
or credits 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.
Thus, 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
the common units.
- 23 -
Current law may change, causing us to be treated as a corporation for federal income tax purposes
or otherwise subjecting us to entity-level taxation. For example, because of widespread state
budget deficits, several states are evaluating ways to subject partnerships to entity-level
taxation through the imposition of state income, franchise or other forms of taxation. If any state
were to impose a tax upon us as an entity, the cash available for distribution to unitholders would
be reduced. The 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, then the minimum
quarterly distribution amount and the target distribution amounts will be adjusted to reflect the
impact of that law on us.
A successful IRS contest of the federal income tax positions we take may adversely impact the
market for our common units, and the costs of any contest will be borne by our unitholders and our
general partner.
We have not requested any ruling from the IRS with respect to our treatment as a partnership for
federal income tax purposes or any other tax matter affecting us. The IRS may adopt positions that
differ from the positions we have taken or may take on tax matters. It may be necessary to resort
to administrative or court proceedings to sustain some or all of the positions we take. A court may
not agree with some or all of the positions we take. Any contest with the IRS may materially and
adversely impact the market for our common units and the price at which they trade. In addition,
the costs of any contest with the IRS will result in a reduction in cash available for distribution
to our unitholders and our general partner and thus will be borne indirectly by our unitholders and
our general partner.
Unitholders may be required to pay taxes on their share of taxable income even if they do not
receive any cash distributions from us.
Unitholders may be required to pay federal income taxes and, in some cases, state and local income
taxes on their share of our taxable income, whether or not they receive 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 that results from their share of our taxable income.
Tax gain or loss on the disposition of our common units could be different than expected.
If a unitholder sells common units, it will recognize gain or loss equal to the difference between
the amount realized and its tax basis in those common units. Prior distributions to a unitholder in
excess of the total net taxable income it was allocated for a common unit, which decreased its tax
basis in that common unit, will, in effect, become taxable income to the unitholder if the common
unit is sold at a price greater than its tax basis in that common unit, even if the price received
is less than the original cost. A substantial portion of the amount realized, whether or not
representing gain, may be ordinary income.
Tax-exempt entities, regulated investment companies or foreign persons may have adverse tax
consequences from owning common units.
Investment in common units by tax-exempt entities, regulated investment companies or mutual funds
and foreign persons raises issues unique to them. For example, virtually all of our income
allocated to organizations exempt from federal income tax, including individual retirement accounts
and other retirement plans, will be unrelated business taxable income and will be taxable to them.
Recent legislation treats net income derived from the ownership of certain publicly traded
partnerships (including us) as qualifying income to a regulated investment company. Distributions
to foreign persons will be reduced by withholding taxes at the highest effective U.S. federal
income tax rate for individuals, and foreign persons will be required to file federal income tax
returns and pay tax on their share of our taxable income.
We treat each purchaser of common units as having the same tax benefits without regard to the units
purchased. The IRS may challenge this treatment, which could adversely affect the value of the
common units.
- 24 -
Because we cannot match transferors and transferees of common units, we have adopted depreciation
and amortization positions that may not precisely conform with all aspects of existing Treasury
regulations. A successful IRS challenge to those positions could adversely affect the amount of tax
benefits available to a unitholder. It also could affect the timing of these tax benefits or the
amount of gain from the sale of common units and could have a negative impact on the value of our
common units or result in audit adjustments to unitholder tax returns.
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 will likely 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 New Mexico, Arizona, Texas, Washington, Utah, Oklahoma and Idaho. Of those
states, only Texas and Washington do not currently impose a state income tax. 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 and local tax returns.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month
period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if there
is a sale or exchange of 50% or more of the total interests in our capital and profits within a
twelve-month period. Our termination would, among other things, result in the closing of our
taxable year for all unitholders and could result in a deferral of depreciation deductions
allowable in computing our taxable income.
Item 1B. Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
Item 2. Properties
PIPELINES
Our refined product pipelines transport light refined products from Hollys Navajo Refinery in New
Mexico and Alons Big Spring Refinery in Texas to their customers in the metropolitan and rural
areas of Texas, New Mexico, Arizona, Colorado, Utah, Oklahoma and northern Mexico. The refined
products transported in these pipelines include conventional gasolines, federal, state and local
specification reformulated gasoline, low-octane gasoline for oxygenate blending, distillates that
include high- and low-sulfur diesel and jet fuel and LPGs (such as propane, butane and isobutane).
Our intermediate product pipelines consist of two parallel pipelines that originate at Hollys
Lovington, New Mexico refining facilities and terminate at Hollys Artesia, New Mexico refining
facilities. These pipelines transport intermediate feedstocks and crude oil for Hollys refining
operations in New Mexico.
Our 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, 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.
- 25 -
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2007 |
|
2006 |
|
2005(1) |
|
2004 |
|
2003 |
|
Refined products transported for (bpd): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Holly |
|
|
142,447 |
|
|
|
126,929 |
|
|
|
94,473 |
|
|
|
65,525 |
|
|
|
51,456 |
|
Third parties (2) |
|
|
62,720 |
|
|
|
62,655 |
|
|
|
65,053 |
|
|
|
29,967 |
|
|
|
23,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
205,167 |
|
|
|
189,584 |
|
|
|
159,526 |
|
|
|
95,492 |
|
|
|
74,925 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total barrels in thousands (mbbls) |
|
|
74,886 |
|
|
|
69,198 |
|
|
|
58,227 |
|
|
|
34,950 |
|
|
|
27,348 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes volumes transported on the pipelines acquired from Alon on February 28, 2005, and
volumes transported on the Intermediate Pipelines acquired on July 8, 2005. |
|
(2) |
|
Includes Rio Grande Pipeline volumes beginning June 30, 2003, when we increased our ownership
from 25% to 70% and began consolidating the results of Rio Grande Pipeline. |
The following table sets forth certain operating data for each of our petroleum product pipelines.
Except as shown below, we own 100% of our refined 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 20,000 barrels of refined
product per day. Effective September 1, 2008, the leased capacity shall decrease 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate |
|
|
|
|
Diameter |
|
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 |
|
|
|
215 |
|
|
|
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(4) |
|
|
6/8 |
|
|
|
105 |
|
|
|
20,000 |
|
Big Spring, TX to Wichita Falls, TX(4) |
|
|
6/8 |
|
|
|
227 |
|
|
|
23,000 |
|
Wichita Falls, TX to Duncan, OK(4) |
|
|
6 |
|
|
|
47 |
|
|
|
21,000 |
|
Midland, TX to Orla, TX(4) |
|
|
8/10 |
|
|
|
135 |
|
|
|
25,000 |
|
Intermediate Product Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Lovington, NM to Artesia, NM(5) |
|
|
8 |
|
|
|
65 |
|
|
|
48,000 |
|
Lovington, NM to Artesia, NM(5) |
|
|
10 |
|
|
|
65 |
|
|
|
72,000 |
|
Rio Grande Pipeline Company: |
|
|
|
|
|
|
|
|
|
|
|
|
Rio Grande Pipeline(6) |
|
|
8 |
|
|
|
249 |
|
|
|
27,000 |
|
|
|
|
(1) |
|
Includes 20,000 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) |
|
Acquired from Alon on February 28, 2005. |
|
(5) |
|
Acquired from Holly on July 8, 2005. |
|
(6) |
|
We have a 70% joint venture interest in the entity that owns this pipeline that runs from
Midland, TX to El Paso, TX. Capacity reflects a 100% interest. |
Holly shipped an aggregate of 55% of the petroleum products transported on our refined product
pipelines and 100% of the petroleum products transported on our Intermediate Pipelines in 2007.
These
pipelines transported approximately 96% of the light refined products produced by Hollys Navajo
Refinery in 2007.
- 26 -
Artesia, New Mexico to El Paso, Texas
The Artesia to El Paso refined product pipeline is regulated by the FERC. It was constructed in
1959 and consists of 156 miles of 6-inch pipeline. This pipeline is used for the shipment of
refined products produced at Hollys Navajo Refinery to our El Paso terminal, where we deliver to
common carrier pipelines for transportation to Arizona, northern New Mexico and northern Mexico and
to the terminals truck rack for local delivery by tanker truck. Holly is the only shipper on this
pipeline. The refined products shipped on this pipeline represented 17% of the total light refined
products produced at Hollys Navajo Refinery during 2007. Refined products produced at Hollys
Navajo Refinery destined for El Paso are transported on either this pipeline or our Artesia to Orla
to El Paso pipeline.
Artesia, New Mexico to Orla, Texas to El Paso, Texas
The Artesia to Orla to El Paso refined product pipeline is a common-carrier pipeline regulated by
the FERC and consists of three segments:
|
|
|
an 8-inch, 67-mile and a 12-inch, 14-mile segment from the Navajo Refinery to Orla,
Texas, constructed in 1981; |
|
|
|
|
a 12-inch, 99-mile segment from Orla to outside El Paso, Texas, constructed in 1996; and |
|
|
|
|
an 8-inch, 35-mile segment from outside El Paso to our El Paso terminal, constructed in
the mid 1950s |
There are two shippers on this pipeline, Holly and Alon. In 2007, this pipeline transported to our
El Paso terminal 55% of the light refined products produced at Hollys Navajo Refinery. As
mentioned above, refined products destined to the El Paso terminal are delivered to common carrier
pipelines for transportation to Arizona, northern New Mexico and northern Mexico and to the
terminals truck rack for local delivery by tanker truck.
At Orla, our pipeline also receives volumes of gasoline and diesel via a tie-in to our pipeline
from Alons Big Spring, Texas refinery.
Artesia, New Mexico to Moriarty, New Mexico
The Artesia to Moriarty refined product pipeline consists of a 60-mile, 12-inch pipeline from
Hollys Artesia facility to White Lakes Junction, New Mexico that was constructed in 1999, and
approximately 155 miles of 8-inch pipeline that was constructed in 1973 and extends from White
Lakes Junction to our Moriarty terminal, where it also connects to our Moriarty to Bloomfield
pipeline. We own the 12-inch pipeline from Artesia to White Lakes Junction. We lease the White
Lakes Junction to Moriarty segment of this pipeline and the Moriarty to Bloomfield pipeline
described below, from Mid-America Pipeline Company, LLC under a long-term lease agreement entered
into in 1996, which expires in 2017 and has two ten-year extensions at our option. At our Moriarty
terminal, volumes shipped on this pipeline can be transported to other markets in the area,
including Albuquerque, Santa Fe and west Texas, via tanker truck. The 155-mile White Lakes
Junction to Moriarty segment of this pipeline is operated by Mid-America (or its designee). Holly
is the only shipper on this pipeline. We currently pay a monthly fee (which is subject to
adjustments based on changes in the PPI) of $488,000 to Mid-America to lease the White Lakes
Junction to Moriarty and Moriarty to Bloomfield pipelines.
Moriarty, New Mexico to Bloomfield, New Mexico
The Moriarty to Bloomfield refined product pipeline was constructed in 1973 and consists of 191
miles of 8-inch pipeline leased from Mid-America. This pipeline serves our terminal in Bloomfield.
At our Bloomfield terminal, volumes shipped on this pipeline are transported to other markets in
the Four Corners area via tanker truck. This pipeline is operated by Mid-America (or its
designee). Holly is the only shipper on this pipeline.
Big Spring, Texas to Abilene, Texas
The Big Spring to Abilene refined product pipeline was constructed in 1957 and consists of 100
miles of 6-inch pipeline and 5 miles of 8-inch pipeline. This pipeline is used for the shipment of
refined products produced at Alons Big Spring Refinery to the Abilene terminal. Alon is the only
shipper on this pipeline.
- 27 -
Big Spring, Texas to Wichita Falls, Texas
Segments of the Big Spring to Wichita Falls refined product pipeline were constructed in 1969 and
1989, and consist of 95 miles of 6-inch pipeline and 132 miles of 8-inch pipeline. This pipeline
is used for the shipment of refined products produced at Alons Big Spring Refinery to the Wichita
Falls terminal. Alon is the only shipper on this pipeline.
Wichita Falls, Texas to Duncan, Oklahoma
The Wichita Falls to Duncan refined product pipeline is a common carrier and is regulated by the
FERC. It was constructed in 1958 and consists of 47 miles of 6-inch pipeline. This pipeline is
used for the shipment of refined products from the Wichita Falls terminal to Alons Duncan
terminal, which we do not own. Alon is the only shipper on this pipeline.
Midland, Texas to Orla, Texas
Segments of the Midland to Orla refined product pipeline were constructed in 1928 and 1998, and
consist of 50 miles of 10-inch pipeline and 85 miles of 8-inch pipeline. This pipeline is used for
the shipment of refined products produced at Alons Big Spring Refinery from Midland to our tank
farm at Orla. Alon is the only shipper on this pipeline.
8 Pipeline from Lovington, New Mexico to Artesia, New Mexico
The 65-mile 8-inch diameter pipeline was constructed in 1981. This pipeline is used for the
shipment of intermediate feedstocks, crude oil and LPGs from Hollys Lovington facility to its Artesia
facility.
10 Pipeline from Lovington, New Mexico to Artesia, New Mexico
The 65-mile 10-inch diameter pipeline was constructed in 1999. This pipeline is used for the
shipment of intermediate feedstocks and crude oil from Hollys Lovington facility to its Artesia
facility. Holly is the only shipper on this pipeline.
Rio Grande Pipeline
We own a 70% interest in Rio Grande, a joint venture that owns a 249-mile, 8-inch common carrier
LPG pipeline regulated by the FERC. The other owner of Rio Grande is a subsidiary of BP. The
pipeline originates from a connection with an Enterprise pipeline in west Texas at Lawson Junction
which serves as its primary receipt point, although there is an additional receipt point near
Midland, Texas. The pipeline terminates at the Mexico border near San Elizario, Texas. The
pipeline transports LPGs for ultimate use by Petróleos Mexicanos (PEMEX, the government-owned
energy company of Mexico.) Rio Grande does not own any facilities or pipelines in Mexico. The
pipeline has a current capacity of approximately 27,000 bpd. This pipeline was originally
constructed in the mid 1950s, was first reconditioned in 1988, and subsequently reconditioned in
1996 and 2003. Approximately 75 miles of this pipeline has been replaced with new pipe, and an
additional 50 miles has been recoated.
Rio Grande was formed in 1996, at which time we contributed nearly 220 miles of pipeline from near
Odessa, Texas to outside El Paso, Texas in exchange for a 25% interest in the joint venture. Rio
Grande Pipeline began operations in 1997. In June 2003, we acquired an additional 45% interest in
the joint venture for $28.7 million. Currently, only LPGs are transported on this
pipeline, and BP is the only shipper. BPs contract expires in April 2008. The contract provides
that BP will ship a minimum average of 16,500 bpd during the term of the agreement. The tariff
rates and shipping regulations are regulated by the FERC.
- 28 -
In January 2005, Rio Grande appointed us as operator of the pipeline system effective April 1, 2005
through January 31, 2010. We paid $745,000 to the then-current operator as an inducement to and
consideration for its early resignation. As operator, we receive a management fee of $1.1 million
per year, adjusted annually for any changes in the PPI.
An officer of HLS is one of the two members of Rio Grandes management committee.
REFINED PRODUCT TERMINALS AND TRUCK RACKS
Our refined product terminals receive products from pipelines, 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, |
|
|
2007 |
|
2006 |
|
2005(1) |
|
2004 |
|
2003 |
|
Refined products terminalled for (bpd): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Holly |
|
|
119,910 |
|
|
|
118,202 |
|
|
|
120,795 |
|
|
|
114,991 |
|
|
|
86,780 |
|
Third parties |
|
|
45,457 |
|
|
|
43,285 |
|
|
|
42,334 |
|
|
|
24,821 |
|
|
|
19,956 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
165,367 |
|
|
|
161,487 |
|
|
|
163,129 |
|
|
|
139,812 |
|
|
|
106,736 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (mbbls) |
|
|
60,359 |
|
|
|
58,943 |
|
|
|
59,542 |
|
|
|
51,171 |
|
|
|
38,959 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes volumes for the terminals and tank farm acquired from Alon February 28, 2005. |
- 29 -
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(1) |
|
(barrels) |
|
Tanks |
|
Source |
|
Mode of Delivery |
El Paso, TX |
|
|
507,000 |
|
|
|
16 |
|
|
Pipeline/ rail |
|
Truck/Pipeline |
Moriarty, NM |
|
|
189,000 |
|
|
|
9 |
|
|
Pipeline |
|
Truck |
Bloomfield, NM |
|
|
193,000 |
|
|
|
7 |
|
|
Pipeline |
|
Truck |
Tucson, AZ(2) |
|
|
176,000 |
|
|
|
9 |
|
|
Pipeline |
|
Truck |
Mountain Home, ID(3) |
|
|
120,000 |
|
|
|
3 |
|
|
Pipeline |
|
Pipeline |
Boise, ID(4) |
|
|
111,000 |
|
|
|
9 |
|
|
Pipeline |
|
Pipeline |
Burley, ID(4) |
|
|
70,000 |
|
|
|
7 |
|
|
Pipeline |
|
Truck |
Spokane, WA |
|
|
333,000 |
|
|
|
32 |
|
|
Pipeline/Rail |
|
Truck |
Abilene, TX(5) |
|
|
127,000 |
|
|
|
5 |
|
|
Pipeline |
|
Truck/Pipeline |
Wichita Falls, TX(5) |
|
|
220,000 |
|
|
|
11 |
|
|
Pipeline |
|
Truck/Pipeline |
Orla tank farm(5) |
|
|
135,000 |
|
|
|
5 |
|
|
Pipeline |
|
Pipeline |
Artesia facility truck rack |
|
|
N/A |
|
|
|
N/A |
|
|
Refinery |
|
Truck |
Woods Cross facility
truck rack |
|
|
N/A |
|
|
|
N/A |
|
|
Refinery |
|
Truck/Pipeline |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2,181,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We closed our Albuquerque terminal in the fourth quarter of 2007. |
|
(2) |
|
The Tucson terminal consists of two parcels. The underlying ground on both parcels is leased. |
|
(3) |
|
Handles only jet fuel. |
|
(4) |
|
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. |
|
(5) |
|
Acquired from Alon on February 28, 2005. |
El Paso Terminal
We receive light refined products at this terminal from Hollys Artesia facility through our
Artesia to El Paso and Artesia to Orla to El Paso pipelines and by rail that account for
approximately 68% of the volumes at this terminal. We also receive product from Alons Big Spring
Refinery that accounted for 32% of the volumes at this terminal in 2007. Refined products received
at this terminal are sold locally via the truck rack or transported to our Tucson terminal 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. and a terminal connected to the Longhorn Pipeline.
Moriarty Terminal
We receive light refined products at this terminal from Hollys Artesia facility through our
pipelines. Refined products received at this terminal are sold locally, via the truck rack; Holly
is our only customer at this terminal. There are no competing terminals in Moriarty.
Bloomfield Terminal
We receive light refined products at this terminal from Hollys Artesia facility through our
pipelines. Refined products received at this terminal are sold locally, via the truck rack; Holly
is our only customer at this terminal. Competition in this market includes a refinery and truck
loading rack owned by Western Refining, Inc.
Tucson Terminal
The Tucson terminal consists of two parcels. On one parcel, we lease the underlying ground as a
50% co-tenant with a division of NuStar pursuant to which we own 50% of the improvements on that
parcel. On the other parcel, our joint venture with NuStar leases the underlying ground and owns
the improvements. This joint venture agreement gives us rights to 100% of the terminal capacity
(for both parcels), which is operated by NuStar for a fee. We receive light refined products at
this terminal from Kinder Morgans East System pipeline, which transports refined products from
Hollys Artesia facility that it receives at our El Paso terminal. Refined products received at
this terminal are sold locally, via the truck rack. Competition in this market includes terminals
owned by Kinder Morgan and CalJet.
- 30 -
Mountain Home Terminal
We receive jet fuel from third parties at this terminal that is transported on Chevrons Salt Lake
City to Boise, Idaho pipeline. We then transport the jet fuel from the Mountain Home terminal
through our 13-mile, 4-inch pipeline to the United States Air Force base outside of Mountain Home.
Our pipeline associated with this terminal is the only pipeline that supplies jet fuel to the air
base. We are paid a single fee, from the Defense Energy Support Center, for injecting, storing,
testing and transporting jet fuel at this terminal.
Boise Terminal
We and Sinclair Transportation Company (Sinclair) each own a 50% interest in the Boise terminal. Sinclair is the operator of the
terminal. The Boise terminal receives light refined products from Holly and Sinclair shipped
through Chevrons pipeline originating in Salt Lake City, Utah. The Woods Cross Refinery, as well
as other refineries in the Salt Lake City area, and Pioneer Pipeline Co.s terminal in Salt Lake
City are connected to the Chevron pipeline. All loading of products out of the Boise terminal is
conducted at Chevrons loading rack, which is connected to the Boise terminal by pipeline. Holly
and Sinclair are the only customers at this terminal.
Burley Terminal
We and Sinclair each own a 50% interest in the Burley terminal. Sinclair is the operator of the
terminal. The Burley terminal receives product from Holly and Sinclair shipped through Chevrons
pipeline originating in Salt Lake City, Utah. Refined products received at this terminal are sold
locally, via the truck rack. Holly and Sinclair are the only customers at this terminal.
Spokane Terminal
This terminal is connected to the Woods Cross Refinery via a Chevron common carrier pipeline. The
Spokane terminal also is supplied by Chevron and Yellowstone pipelines and by rail and truck.
Refined products received at this terminal are sold locally, via the truck rack. Shell and Chevron
are the major customers at this terminal. Other terminals in the Spokane area include terminals
owned by ExxonMobil and ConocoPhillips.
Abilene Terminal
This terminal receives refined products from Alons Big Spring Refinery, which accounted for all of
its volumes in 2007. Refined products received at this terminal are sold locally via a truck rack
or pumped over a 2-mile pipeline to Dyess Air Force Base. Alon is the only customer at this
terminal.
Wichita Falls Terminal
This terminal receives refined products from Alons Big Spring Refinery, which accounted for all of
its volumes in 2007. Refined products received at this terminal are sold via a truck rack or
shipped via pipeline connections to Alons terminal in Duncan, Oklahoma and to NuStars Southlake pipeline. Alon is the only customer at this
terminal.
Orla Tank Farm
The Orla tank farm was constructed in 1998. It receives refined products from Alons Big Spring
Refinery that accounted for all of its volumes in 2007. 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 Hollys Artesia facility loads light refined products, produced at the facility,
onto tanker trucks for delivery to markets in the surrounding area. Holly is the only customer of
this truck rack.
Woods Cross Facility Truck Rack
The truck rack at Hollys Woods Cross facility loads light refined products produced at Hollys
Woods Cross Refinery onto tanker trucks for delivery to markets in the surrounding area. Holly is
the only customer of this truck rack; Holly also makes transfers to a common carrier pipeline at
this facility.
- 31 -
PIPELINE AND TERMINAL CONTROL OPERATIONS
All of our pipelines are operated via geosynchronous satellite, microwave, radio and frame relay
communication systems from our central control room located in Artesia, New Mexico. We also
monitor activity at our terminals from this control room.
The control center operates with state-of-the-art System Control and Data Acquisition, or SCADA,
systems. Our control center is equipped with computer systems designed to continuously monitor
operational data, including refined product and crude oil throughput, flow rates, and pressures.
In addition, the control center monitors alarms and throughput balances. The control center
operates remote pumps, motors, engines, and valves associated with the delivery of refined products
and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound
automatic alarms if operational conditions outside of pre-established parameters occur, and provide
for remote-controlled shutdown of pump stations on the pipelines. Pump stations and
meter-measurement points on the pipelines are linked by satellite or telephone communication
systems for remote monitoring and control, which reduces our requirement for full-time on-site
personnel at most of these locations.
Item 3. Legal Proceedings
We are a party to various legal and regulatory proceedings, which we believe will not have a
material adverse impact on our financial condition, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth quarter of 2007.
- 32 -
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 |
|
|
Years Ended December 31, |
|
High |
|
Low |
|
Distributions |
|
Trading Volume |
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
48.09 |
|
|
$ |
42.04 |
|
|
$ |
0.715 |
|
|
|
1,065,300 |
|
Third Quarter |
|
$ |
57.24 |
|
|
$ |
43.10 |
|
|
$ |
0.705 |
|
|
|
1,273,100 |
|
Second Quarter |
|
$ |
56.69 |
|
|
$ |
46.55 |
|
|
$ |
0.690 |
|
|
|
1,231,600 |
|
First Quarter |
|
$ |
49.97 |
|
|
$ |
39.50 |
|
|
$ |
0.675 |
|
|
|
948,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
41.10 |
|
|
$ |
37.90 |
|
|
$ |
0.665 |
|
|
|
876,800 |
|
Third Quarter |
|
$ |
40.44 |
|
|
$ |
35.80 |
|
|
$ |
0.655 |
|
|
|
957,700 |
|
Second Quarter |
|
$ |
42.58 |
|
|
$ |
38.15 |
|
|
$ |
0.640 |
|
|
|
704,100 |
|
First Quarter |
|
$ |
42.75 |
|
|
$ |
37.00 |
|
|
$ |
0.625 |
|
|
|
1,165,000 |
|
A distribution for the quarter ended December 31, 2007 of $0.725 per unit was paid on February 14,
2008.
As of February 7, 2008, we had approximately 4,620 common unitholders, including beneficial owners
of common units held in street name.
We consider cash distributions to unitholders on a quarterly basis, although there is no assurance
as to the future cash distributions since they are dependent upon future earnings, cash flows,
capital requirements, financial condition and other factors. Our revolving credit facility
prohibits us from making cash distributions if any potential default or event of default, as
defined in the Credit Agreement, occurs or would result from the cash distribution. The indenture
relating to our Senior Notes prohibits us from making cash distributions under certain
circumstances.
Within 45 days after the end of each quarter, we distribute all of our available cash (as defined
in our partnership agreement) to unitholders of record on the applicable record date. The amount
of available cash generally is all cash on hand at the end of the quarter: less the amount of cash
reserves established by our general partner to provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments, or other agreements; or provide funds for
distributions to our unitholders and to our general partner for any one or more of the next four
quarters; plus all cash on hand on the date of determination of available cash for the quarter
resulting from working capital borrowings made after the end of the quarter. Working capital
borrowings are generally borrowings that are made under our revolving credit facility and in all
cases are used solely for working capital purposes or to pay distributions to partners.
Upon the closing of our initial public offering, Holly received 7,000,000 subordinated units.
During the subordination period, the common units have the right to receive distributions of
available cash from operating surplus in an amount equal to the minimum quarterly distribution of
$0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the
common units from prior quarters, before any distributions of available cash from operating surplus
may be made on the subordinated units. The purpose of the subordinated units is to increase the
likelihood that during the subordination period there will be available cash to be distributed on
the common units. The subordination period will extend until the first day of any quarter
beginning after June 30, 2009 that each of the following tests are met: distributions of available
cash from operating surplus on each of the outstanding common units and subordinated units equaled
or exceeded the minimum quarterly distribution for each of the three
- 33 -
consecutive, non-overlapping four-quarter periods immediately preceding that date; the adjusted
operating surplus (as defined in our partnership agreement) generated during each of the three
consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or
exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and
subordinated units during those periods on a fully diluted basis and the related distribution on
the 2% general partner interest during those periods; and there are no arrearages in payment of the
minimum quarterly distribution on the common units. If the unitholders remove the general partner
without cause, the subordination period may end before June 30, 2009.
We issued 937,500 of our Class B subordinated units in connection with the Alon transaction in
2005. The Class B subordinated units issued to Alon vote as a single class and rank equally with
our existing subordinated units. There is a subordination period with respect to the Class B
subordinated units with generally similar provisions to the subordinated units held by Holly,
except that the subordination period will end on the last day of any quarter ending on or after
March 31, 2010 if Alon has not defaulted on its minimum volume commitment payment obligations for
the three consecutive, non-overlapping four quarter periods immediately preceding that date,
subject to certain grace periods. If Holly is removed as the general partner without cause, the
subordination period for the Class B subordinated units may end before March 31, 2010.
We make distributions of available cash from operating surplus for any quarter during any
subordination period in the following manner: first, 98% to the common unitholders, pro rata, and
2% to the general partner, until we distribute for each outstanding common unit an amount equal to
the minimum quarterly distribution for that quarter; second, 98% to the common unitholders, pro
rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount
equal to any arrearages in payment of the minimum quarterly distribution on the common units for
any prior quarters during the subordination period; third, 98% to the subordinated unitholders, pro
rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal
to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the
minimum quarterly distributions is distributed to the unitholders and the general partner based on
the percentages below.
The general partner, HEP Logistics Holdings, L.P., is entitled to incentive distributions if the
amount we distribute with respect to any quarter exceeds specified target levels shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage Interest in |
|
|
Total Quarterly Distribution |
|
Distributions |
|
|
Target Amount |
|
Unitholders |
|
General Partner |
Minimum Quarterly Distribution |
|
|
$0.50 |
|
|
|
98 |
% |
|
|
2 |
% |
First Target Distribution |
|
Up to $0.55 |
|
|
98 |
% |
|
|
2 |
% |
Second Target Distribution |
|
above $0.55 up to $0.625 |
|
|
85 |
% |
|
|
15 |
% |
Third Target distribution |
|
above $0.625 up to $0.75 |
|
|
75 |
% |
|
|
25 |
% |
Thereafter |
|
Above $0.75 |
|
|
50 |
% |
|
|
50 |
% |
- 34 -
Item 6. Selected Financial Data
The following table shows selected financial information for HEP. This table should be read in
conjunction with Item 7, Managements Discussion and Analysis of Financial Condition and Results
of Operations and the consolidated financial statements of HEP and related notes thereto included
elsewhere in this Form 10-K. See Historical Results of Operations below for a description of
factors affecting the comparability of our financial information for years prior to 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined |
|
|
Successor |
|
|
Predecessor |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 13, 2004 |
|
|
January 1, |
|
|
|
|
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Through |
|
|
2004 Through |
|
|
Year Ended |
|
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
December 31, |
|
|
July 12, |
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004(1) |
|
|
2004 |
|
|
2004 |
|
|
2003 |
|
|
|
(In thousands, except per unit data) |
|
Statement Of Income Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
105,407 |
|
|
$ |
89,194 |
|
|
$ |
80,120 |
|
|
$ |
67,766 |
|
|
$ |
28,182 |
|
|
$ |
39,584 |
|
|
$ |
30,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
32,911 |
|
|
|
28,630 |
|
|
|
25,332 |
|
|
|
23,641 |
|
|
|
10,104 |
|
|
|
13,537 |
|
|
|
24,193 |
|
Depreciation and amortization |
|
|
14,382 |
|
|
|
15,330 |
|
|
|
14,201 |
|
|
|
7,224 |
|
|
|
3,241 |
|
|
|
3,983 |
|
|
|
6,453 |
|
General and administrative |
|
|
5,043 |
|
|
|
4,854 |
|
|
|
4,047 |
|
|
|
1,860 |
|
|
|
1,859 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52,336 |
|
|
|
48,814 |
|
|
|
43,580 |
|
|
|
32,725 |
|
|
|
15,204 |
|
|
|
17,521 |
|
|
|
30,646 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
53,071 |
|
|
|
40,380 |
|
|
|
36,540 |
|
|
|
35,041 |
|
|
|
12,978 |
|
|
|
22,063 |
|
|
|
154 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
533 |
|
|
|
899 |
|
|
|
649 |
|
|
|
144 |
|
|
|
65 |
|
|
|
79 |
|
|
|
291 |
|
Interest expense |
|
|
(13,289 |
) |
|
|
(13,056 |
) |
|
|
(9,633 |
) |
|
|
(697 |
) |
|
|
(697 |
) |
|
|
|
|
|
|
|
|
Gain on sale of assets |
|
|
298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of Rio Grande Pipeline
Company |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
894 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,458 |
) |
|
|
(12,157 |
) |
|
|
(8,984 |
) |
|
|
(553 |
) |
|
|
(632 |
) |
|
|
79 |
|
|
|
1,185 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before minority interest |
|
|
40,613 |
|
|
|
28,223 |
|
|
|
27,556 |
|
|
|
34,488 |
|
|
|
12,346 |
|
|
|
22,142 |
|
|
|
1,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interest in Rio Grande Pipeline
Company |
|
|
(1,067 |
) |
|
|
(680 |
) |
|
|
(740 |
) |
|
|
(1,994 |
) |
|
|
(956 |
) |
|
|
(1,038 |
) |
|
|
(758 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
39,546 |
|
|
|
27,543 |
|
|
|
26,816 |
|
|
|
32,494 |
|
|
|
11,390 |
|
|
|
21,104 |
|
|
|
581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
(275 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
39,271 |
|
|
|
27,543 |
|
|
|
26,816 |
|
|
|
32,494 |
|
|
|
11,390 |
|
|
|
21,104 |
|
|
|
581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Predecessor |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,104 |
|
|
|
|
|
|
|
21,104 |
|
|
|
581 |
|
General partner interest in net income |
|
|
2,932 |
|
|
|
1,710 |
|
|
|
721 |
|
|
|
228 |
|
|
|
228 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
36,339 |
|
|
$ |
25,833 |
|
|
$ |
26,095 |
|
|
$ |
11,162 |
|
|
$ |
11,162 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit basic
and diluted |
|
$ |
2.26 |
|
|
$ |
1.60 |
|
|
$ |
1.70 |
|
|
|
|
|
|
$ |
0.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions declared per unit
applicable to limited partners |
|
$ |
2.785 |
|
|
$ |
2.585 |
|
|
$ |
2.225 |
|
|
|
|
|
|
$ |
0.435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA (2) |
|
$ |
66,684 |
|
|
$ |
55,030 |
|
|
$ |
50,001 |
|
|
$ |
40,271 |
|
|
$ |
15,263 |
|
|
$ |
25,008 |
|
|
$ |
6,743 |
|
Cash flows from operating activities |
|
$ |
59,056 |
|
|
$ |
45,853 |
|
|
$ |
42,628 |
|
|
$ |
15,867 |
|
|
$ |
15,371 |
|
|
$ |
496 |
|
|
$ |
5,909 |
|
Cash flows from investing activities |
|
$ |
(9,632 |
) |
|
$ |
(9,107 |
) |
|
$ |
(131,795 |
) |
|
$ |
(2,977 |
) |
|
$ |
(305 |
) |
|
$ |
(2,672 |
) |
|
$ |
(27,947 |
) |
Cash flows from financing activities |
|
$ |
(50,658 |
) |
|
$ |
(45,774 |
) |
|
$ |
90,646 |
|
|
$ |
(480 |
) |
|
$ |
1,770 |
|
|
$ |
(2,250 |
) |
|
$ |
28,372 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures (3) |
|
$ |
1,863 |
|
|
$ |
1,095 |
|
|
$ |
364 |
|
|
$ |
1,197 |
|
|
$ |
305 |
|
|
$ |
892 |
|
|
$ |
1,934 |
|
Expansion capital expenditures |
|
|
8,094 |
|
|
|
8,012 |
|
|
|
3,519 |
|
|
|
1,780 |
|
|
|
|
|
|
|
1,780 |
|
|
|
4,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
9,957 |
|
|
$ |
9,107 |
|
|
$ |
3,883 |
|
|
$ |
2,977 |
|
|
$ |
305 |
|
|
$ |
2,672 |
|
|
$ |
6,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment |
|
$ |
158,600 |
|
|
$ |
160,484 |
|
|
$ |
162,298 |
|
|
$ |
74,626 |
|
|
$ |
74,626 |
|
|
$ |
95,337 |
|
|
$ |
95,826 |
|
Total assets |
|
$ |
238,904 |
|
|
$ |
245,771 |
|
|
$ |
254,775 |
|
|
$ |
103,758 |
|
|
$ |
103,758 |
|
|
$ |
156,373 |
|
|
$ |
140,425 |
|
Long-term debt |
|
$ |
181,435 |
|
|
$ |
180,660 |
|
|
$ |
180,737 |
|
|
$ |
25,000 |
|
|
$ |
25,000 |
|
|
$ |
|
|
|
$ |
|
|
Total liabilities |
|
$ |
200,348 |
|
|
$ |
198,582 |
|
|
$ |
190,962 |
|
|
$ |
28,998 |
|
|
$ |
28,998 |
|
|
$ |
53,146 |
|
|
$ |
57,089 |
|
Net partners equity (4) |
|
$ |
27,816 |
|
|
$ |
36,226 |
|
|
$ |
52,060 |
|
|
$ |
61,528 |
|
|
$ |
61,528 |
|
|
$ |
89,964 |
|
|
$ |
68,860 |
|
- 35 -
|
|
|
(1) |
|
Combined results for the year ended December 31, 2004 is not a calculation based upon
U.S. generally accepted accounting principles (GAAP), and is presented here to provide
the investor with additional information for comparing year-over-year information. |
|
(2) |
|
Earnings before interest, taxes, depreciation and amortization (EBITDA) are
calculated as net income plus (a) interest expense net of interest income and (b)
depreciation and amortization. EBITDA is a non-GAAP measure. However, the amounts
included in the EBITDA calculation are derived from amounts included in our consolidated
financial statements. EBITDA should not be considered as an alternative to net income or
operating income, as an indication of our operating performance or as an alternative to
operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to
similarly titled measures of other companies. EBITDA is presented here because it enhances
an investors understanding of our ability to satisfy principal and interest obligations
with respect to our indebtedness and to use cash for other purposes, including capital
expenditures. EBITDA is also used by our management for internal analysis and as a basis
for compliance with financial covenants. Our reconciliation of EBITDA to net income is
presented below. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined |
|
|
Successor |
|
|
Predecessor |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 13, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
|
January 1, |
|
|
Year |
|
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|
Through |
|
|
2004 Through |
|
|
Ended |
|
|
|
December |
|
|
December |
|
|
December |
|
|
December |
|
|
December |
|
|
July |
|
|
December |
|
|
|
31, 2007 |
|
|
31, 2006 |
|
|
31, 2005 |
|
|
31, 2004 |
|
|
31, 2004 |
|
|
12, 2004 |
|
|
31, 2003 |
|
|
|
(In thousands) |
|
Net income |
|
$ |
39,271 |
|
|
$ |
27,543 |
|
|
$ |
26,816 |
|
|
$ |
32,494 |
|
|
$ |
11,390 |
|
|
$ |
21,104 |
|
|
$ |
581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add depreciation and amortization |
|
|
14,382 |
|
|
|
15,330 |
|
|
|
14,201 |
|
|
|
7,224 |
|
|
|
3,241 |
|
|
|
3,983 |
|
|
|
6,453 |
|
Add state income tax |
|
|
275 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add interest expense |
|
|
13,289 |
|
|
|
13,056 |
|
|
|
9,633 |
|
|
|
697 |
|
|
|
697 |
|
|
|
|
|
|
|
|
|
Subtract interest income |
|
|
(533 |
) |
|
|
(899 |
) |
|
|
(649 |
) |
|
|
(144 |
) |
|
|
(65 |
) |
|
|
(79 |
) |
|
|
(291 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
|
$ |
66,684 |
|
|
$ |
55,030 |
|
|
$ |
50,001 |
|
|
$ |
40,271 |
|
|
$ |
15,263 |
|
|
$ |
25,008 |
|
|
$ |
6,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3) |
|
Maintenance capital expenditures represent capital expenditures to replace partially or
fully depreciated assets to maintain the operating capacity of existing assets.
Maintenance capital expenditures include expenditures required to maintain equipment
reliability, tankage and pipeline integrity, and safety and to address environmental
regulations. |
|
(4) |
|
As a master limited partnership, we distribute our available cash, which exceeds 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. |
Historical Results of Operations
In reviewing the historical results of operations that are presented above, you should be aware of
the following:
Until January 1, 2004, our historical revenues included only actual amounts received from:
|
|
|
third parties who utilized our pipelines and terminals; |
|
|
|
|
Holly for use of our FERC-regulated refined product pipeline; and |
|
|
|
|
Holly for use of the Lovington crude oil pipelines, which were not contributed to our
partnership. |
- 36 -
Until January 1, 2004, we did not record revenue for:
|
|
|
transporting products for Holly on our intrastate refined product pipelines; |
|
|
|
|
providing terminalling services to Holly; and |
|
|
|
|
transporting crude oil and feedstocks on the Intermediate Pipelines that connect Hollys
Artesia and Lovington facilities, which were not contributed to our partnership. |
Commencing January 1, 2004, we began charging Holly fees for the use of all of our pipelines and
terminals at the rates set forth in the Holly PTA.
Furthermore, the historical financial data do not reflect any general and administrative expenses
prior to July 13, 2004 as Holly did not historically allocate any of its general and administrative
expenses to its pipelines and terminals. Our historical results of operations prior to July 13,
2004 include costs associated with crude oil and intermediate product pipelines, which were not
contributed to our partnership.
For periods after commencement of operations by HEP on July 13, 2004, our financial statements
reflect:
|
|
net proceeds from our initial public offering which closed on July 13, 2004 |
|
|
|
the transfer of certain of our predecessors operations to HEP, which |
|
- |
|
includes our predecessors refined product pipeline and terminal assets and short-term
debt due to Holly (which was repaid upon the closing of our initial public offering), and |
|
|
- |
|
excludes our predecessors crude oil systems, intermediate product pipelines, accounts
receivable from or payable to affiliates, and other miscellaneous assets and liabilities; |
|
|
the execution of the Holly PTA and the recognition of revenues derived therefrom; and |
|
|
|
the execution of the Omnibus Agreement with Holly and several of its subsidiaries and the
recognition of allocated general and administrative expenses in addition to direct general and
administrative expense related to our operation as a publicly owned entity. |
NPL constitutes HEPs predecessor. The transfer of ownership of assets from NPL to HEP on July 13,
2004 represented a reorganization of entities under common control and was recorded at NPLs
historical cost. Accordingly, our financial statements include the historical results of
operations of NPL prior to the transfer to HEP.
- 37 -
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
This Item 7, including but not limited to the sections on Liquidity and Capital Resources,
contains forward-looking statements. See Forward-Looking Statements at the beginning of Part I.
In this document, the words we, our, ours and us refer to HEP and its consolidated
subsidiaries or to HEP or an individual subsidiary and not to any other person.
OVERVIEW
HEP is a Delaware limited partnership formed by Holly and is the successor to NPL. We own and
operate substantially all of the refined product pipeline and terminalling assets that support
Hollys refining and marketing operations in west Texas, New Mexico, Utah, Idaho and Arizona and a
70% interest in Rio Grande. HEP is currently 45% owned by Holly.
We operate a system of petroleum product pipelines in Texas, New Mexico and Oklahoma, and
distribution terminals in Texas, New Mexico, Arizona, Utah, Idaho, and Washington. We generate
revenues by charging tariffs for transporting petroleum products through our pipelines and by
charging fees for terminalling refined products and other hydrocarbons, and storing and providing
other services at our terminals. We do not take ownership of products that we transport or
terminal; therefore, we are not directly exposed to changes in commodity prices.
On February 28, 2005, we acquired from Alon four refined products pipelines, an associated tank
farm and two refined products terminals located primarily in Texas that serve Alons Big Spring,
Texas refinery. Please read Alon Transaction under Liquidity and Capital Resources below for
additional information.
On July 8, 2005, we acquired Hollys Intermediate Pipelines which connect its Lovington, New Mexico
and Artesia, New Mexico refining facilities. Please read Holly Intermediate Pipelines
Transaction under Liquidity and Capital Resources below for additional information.
Agreements with Holly
We serve Hollys refineries in New Mexico and Utah under two 15-year pipeline and terminal
agreements. The Holly PTA relates to the pipelines and terminals contributed by Holly to us at the
time of our initial public offering and expires in 2019. The Holly IPA relates to the Intermediate
Pipelines acquired from Holly in July 2005 and expires in 2020. The substantial majority of our
business is devoted to providing transportation and terminalling services to Holly. Following the
July 1, 2007 rate adjustment for the PPI, the volume commitment by Holly under the Holly PTA will
produce at least $39.6 million of revenue for the twelve months ending June 30, 2008. Under the
Holly IPA, Holly agreed to transport volumes of intermediate products on the intermediate pipelines
that following the July 1, 2007 PPI adjustment will result in minimum funds to us of $12.8 million
for the twelve months ended June 30, 2008. If Holly fails to meet its minimum volume commitments
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 may be applied as a credit in
the following four quarters after Hollys minimum obligations are met.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we
have agreed to expand our South System between Artesia, New Mexico and El Paso, Texas. The
expansion of the South System will include replacing 85 miles of 8-inch pipe with 12-inch pipe,
adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing
pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making
related modifications. The cost of this project is estimated to be $48.3 million. Currently, we
are expecting to complete this project by January 2009. The agreement also provides for a tariff
increase, expected to be effective May 1, 2008, on Holly shipments on our refined product
pipelines.
Under the Omnibus Agreement, we pay Holly an annual administrative fee, initially $2.0 million for
each of the three years following the closing of our initial public offering, for the provision by
Holly or its affiliates of various general and administrative services to us. Effective July 1,
2007, the annual fee increased to $2.1 million in accordance with provisions under the agreement.
This fee does not include the salaries of
- 38 -
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.
Please read Agreements with Holly under Item 1, Business for additional information on these
agreements with Holly.
- 39 -
RESULTS OF OPERATIONS
The following tables present our operating income, volume information, and cash flow summary
information for the years ended December 31, 2007, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
|
|
|
December 31, |
|
|
Change from |
|
|
|
2007 |
|
|
2006 |
|
|
2006 |
|
|
|
(In thousands, except per unit data) |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
$ |
36,281 |
|
|
$ |
31,723 |
|
|
$ |
4,558 |
|
Third parties refined product pipelines |
|
|
36,271 |
|
|
|
31,685 |
|
|
|
4,586 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72,552 |
|
|
|
63,408 |
|
|
|
9,144 |
|
Affiliates intermediate pipelines |
|
|
13,731 |
|
|
|
10,733 |
|
|
|
2,998 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86,283 |
|
|
|
74,141 |
|
|
|
12,142 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and truck loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
10,949 |
|
|
|
10,422 |
|
|
|
527 |
|
Third parties |
|
|
5,427 |
|
|
|
4,631 |
|
|
|
796 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,376 |
|
|
|
15,053 |
|
|
|
1,323 |
|
Other affiliates |
|
|
2,748 |
|
|
|
|
|
|
|
2,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
105,407 |
|
|
|
89,194 |
|
|
|
16,213 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
32,911 |
|
|
|
28,630 |
|
|
|
4,281 |
|
Depreciation and amortization |
|
|
14,382 |
|
|
|
15,330 |
|
|
|
(948 |
) |
General and administrative |
|
|
5,043 |
|
|
|
4,854 |
|
|
|
189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52,336 |
|
|
|
48,814 |
|
|
|
3,522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
53,071 |
|
|
|
40,380 |
|
|
|
12,691 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
533 |
|
|
|
899 |
|
|
|
(366 |
) |
Interest expense, including amortization |
|
|
(13,289 |
) |
|
|
(13,056 |
) |
|
|
(233 |
) |
Gain on sale of assets |
|
|
298 |
|
|
|
|
|
|
|
298 |
|
Minority interest in Rio Grande Pipeline Company |
|
|
(1,067 |
) |
|
|
(680 |
) |
|
|
(387 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,525 |
) |
|
|
(12,837 |
) |
|
|
(688 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
39,546 |
|
|
|
27,543 |
|
|
|
12,003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
(275 |
) |
|
|
|
|
|
|
(275 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
39,271 |
|
|
|
27,543 |
|
|
|
11,728 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less general partner interest in net income, including incentive
distributions (1) |
|
|
2,932 |
|
|
|
1,710 |
|
|
|
1,222 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
36,339 |
|
|
$ |
25,833 |
|
|
$ |
10,506 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per unit applicable to limited partners (1) |
|
$ |
2.26 |
|
|
$ |
1.60 |
|
|
$ |
0.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partners units outstanding |
|
|
16,108 |
|
|
|
16,108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(2) |
|
$ |
66,684 |
|
|
$ |
55,030 |
|
|
$ |
11,654 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow (3) |
|
$ |
51,012 |
|
|
$ |
47,219 |
|
|
$ |
3,793 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (bpd)(4) |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
|
77,441 |
|
|
|
69,271 |
|
|
|
8,170 |
|
Third parties refined product pipelines |
|
|
62,720 |
|
|
|
62,655 |
|
|
|
65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
140,161 |
|
|
|
131,926 |
|
|
|
8,235 |
|
Affiliates intermediate pipelines |
|
|
65,006 |
|
|
|
57,658 |
|
|
|
7,348 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
205,167 |
|
|
|
189,584 |
|
|
|
15,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and truck loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
119,910 |
|
|
|
118,202 |
|
|
|
1,708 |
|
Third parties |
|
|
45,457 |
|
|
|
43,285 |
|
|
|
2,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
165,367 |
|
|
|
161,487 |
|
|
|
3,880 |
|
|
|
|
|
|
|
|
|
|
|
Total for petroleum pipelines and terminal assets (bpd) |
|
|
370,534 |
|
|
|
351,071 |
|
|
|
19,463 |
|
|
|
|
|
|
|
|
|
|
|
- 40 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
|
|
|
December 31, |
|
|
Change from |
|
|
|
2006 |
|
|
2005 |
|
|
2005 |
|
|
|
(In thousands, except per unit data) |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
$ |
31,723 |
|
|
$ |
29,288 |
|
|
$ |
2,435 |
|
Third parties refined product pipelines |
|
|
31,685 |
|
|
|
31,447 |
|
|
|
238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63,408 |
|
|
|
60,735 |
|
|
|
2,673 |
|
Affiliates intermediate pipelines |
|
|
10,733 |
|
|
|
4,643 |
|
|
|
6,090 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74,141 |
|
|
|
65,378 |
|
|
|
8,763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and truck loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
10,422 |
|
|
|
10,253 |
|
|
|
169 |
|
Third parties |
|
|
4,631 |
|
|
|
4,489 |
|
|
|
142 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,053 |
|
|
|
14,742 |
|
|
|
311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
89,194 |
|
|
|
80,120 |
|
|
|
9,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
28,630 |
|
|
|
25,332 |
|
|
|
3,298 |
|
Depreciation and amortization |
|
|
15,330 |
|
|
|
14,201 |
|
|
|
1,129 |
|
General and administrative |
|
|
4,854 |
|
|
|
4,047 |
|
|
|
807 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,814 |
|
|
|
43,580 |
|
|
|
5,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
40,380 |
|
|
|
36,540 |
|
|
|
3,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
899 |
|
|
|
649 |
|
|
|
250 |
|
Interest expense, including amortization |
|
|
(13,056 |
) |
|
|
(9,633 |
) |
|
|
(3,423 |
) |
Minority interest in Rio Grande Pipeline Company |
|
|
(680 |
) |
|
|
(740 |
) |
|
|
60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,837 |
) |
|
|
(9,724 |
) |
|
|
(3,113 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
27,543 |
|
|
|
26,816 |
|
|
|
727 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less general partner interest in net income, including incentive
distributions (1) |
|
|
1,710 |
|
|
|
721 |
|
|
|
989 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
25,833 |
|
|
$ |
26,095 |
|
|
$ |
(262 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per unit applicable to limited partners (1) |
|
$ |
1.60 |
|
|
$ |
1.70 |
|
|
$ |
(0.10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partners units outstanding |
|
|
16,108 |
|
|
|
15,356 |
|
|
|
752 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(2) |
|
$ |
55,030 |
|
|
$ |
50,001 |
|
|
$ |
5,029 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow (3) |
|
$ |
47,219 |
|
|
$ |
41,438 |
|
|
$ |
5,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (bpd)(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates refined product pipelines |
|
|
69,271 |
|
|
|
66,206 |
|
|
|
3,065 |
|
Third parties refined product pipelines |
|
|
62,655 |
|
|
|
65,053 |
|
|
|
(2,398 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
131,926 |
|
|
|
131,259 |
|
|
|
667 |
|
Affiliates intermediate pipelines |
|
|
57,658 |
|
|
|
28,267 |
|
|
|
29,391 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
189,584 |
|
|
|
159,526 |
|
|
|
30,058 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals and truck loading racks: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
118,202 |
|
|
|
120,795 |
|
|
|
(2,593 |
) |
Third parties |
|
|
43,285 |
|
|
|
42,334 |
|
|
|
951 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
161,487 |
|
|
|
163,129 |
|
|
|
(1,642 |
) |
|
|
|
|
|
|
|
|
|
|
Total for petroleum pipelines and terminal assets (bpd) |
|
|
351,071 |
|
|
|
322,655 |
|
|
|
28,416 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net income is allocated between limited partners and the general partner interest in
accordance with the provisions of the partnership agreement. Net income allocated to the
general partner includes any incentive distributions declared in the period. The limited
partners interest in net income is divided by the weighted average limited partner units
outstanding in computing the net income per unit applicable to limited partners. |
- 41 -
|
|
|
(2) |
|
EBITDA is calculated as net income plus (a) interest expense net of interest income and (b)
depreciation and amortization. EBITDA is a non-GAAP measure. However, the amounts included
in the EBITDA calculation are derived from amounts included in our consolidated financial
statements. EBITDA should not be considered as an alternative to net income or operating
income, as an indication of our operating performance or as an alternative to operating cash
flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled
measures of other companies. EBITDA is presented here because it is a widely accepted
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, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands) |
|
Net income |
|
$ |
39,271 |
|
|
$ |
27,543 |
|
|
$ |
26,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add interest expense |
|
|
12,281 |
|
|
|
12,088 |
|
|
|
8,848 |
|
Add amortization of discount and deferred debt issuance costs |
|
|
1,008 |
|
|
|
968 |
|
|
|
785 |
|
Subtract interest income |
|
|
(533 |
) |
|
|
(899 |
) |
|
|
(649 |
) |
Add state income tax |
|
|
275 |
|
|
|
|
|
|
|
|
|
Add depreciation and amortization |
|
|
14,382 |
|
|
|
15,330 |
|
|
|
14,201 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
|
$ |
66,684 |
|
|
$ |
55,030 |
|
|
$ |
50,001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3) |
|
Distributable cash flow is not a calculation based upon U.S. GAAP. However, the amounts
included in the calculation are derived from amounts separately presented in our consolidated
financial statements, with the exception of maintenance capital expenditures. Distributable
cash flow should not be considered in isolation or as an alternative to net income or
operating income, as an indication of our operating performance or as an alternative to
operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily
comparable to similarly titled measures of other companies. Distributable cash flow is
presented here because it is a widely accepted financial indicator used by investors to
compare partnership performance. We believe that this measure provides investors an enhanced
perspective of the operating performance of our assets and the cash our business is
generating. |
Set forth below is our calculation of distributable cash flow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands) |
|
Net income |
|
$ |
39,271 |
|
|
$ |
27,543 |
|
|
$ |
26,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add depreciation and amortization |
|
|
14,382 |
|
|
|
15,330 |
|
|
|
14,201 |
|
Add amortization of discount and deferred debt issuance costs |
|
|
1,008 |
|
|
|
968 |
|
|
|
785 |
|
Add (subtract) increase (decrease) in deferred revenue |
|
|
(1,786 |
) |
|
|
4,473 |
|
|
|
|
|
Subtract maintenance capital expenditures* |
|
|
(1,863 |
) |
|
|
(1,095 |
) |
|
|
(364 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow |
|
$ |
51,012 |
|
|
$ |
47,219 |
|
|
$ |
41,438 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
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. |
(4) |
|
The amounts reported include volumes from the assets acquired from Alon starting in March
2005 and the Intermediate Pipelines acquired from Holly starting in July 2005. The amounts
reported in the 2005 periods include volumes on the acquired assets subsequent to the
respective acquisition dates averaged over the full reported periods. |
- 42 -
Results of Operations Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Summary
Net income was $39.3 million for the year ended December 31, 2007, an increase of $11.8 million
from $27.5 million for the year ended December 31, 2006. The increase in overall earnings was
principally due to an increase in volumes transported on our pipeline systems, the effects of the
annual tariff increases on product shipments, the realization of certain previously deferred
revenue and revenue related to the sale of inventory of accumulated terminal overages of refined
product to Holly, partially offset by an increase in our operating costs and expenses. Revenues of
$3.7 million relating to deficiency payments associated with certain guaranteed shipping contracts
was deferred during the year ended December 31, 2007. Such revenue will be recognized in future
periods either as payment for shipments in excess of guaranteed levels or when shipping rights
expire unused after a twelve-month period.
Revenues
Revenues of $105.4 million for the year ended December 31, 2007 were $16.2 million greater than the
$89.2 million for the comparable period of 2006. This increase in revenue was principally due to
an increase in volumes transported on our pipeline systems, the effects of annual tariff increases
on product shipments, an increase in previously deferred revenue realized and revenue related to
the sale of inventory of accumulated terminal overages of refined product to Holly.
The increase in volumes transported on our pipeline systems for the year ended December 31, 2007
as compared to 2006 was principally due to significant downtime at all of the refineries served by
our product distribution network in the second quarter of 2006. Refiners were generally required
to start producing ultra low sulfur diesel fuel (ULSD) by June 2006. To meet this requirement,
many refiners, including Hollys Navajo Refinery and Alons Big Spring Refinery, required downtime
at their refineries so that ULSD-associated projects could be brought on line. Additionally, Holly
completed an expansion of the Navajo Refinery during this period of downtime which resulted in
increased refinery production and has contributed to increased volume shipments on our pipeline
systems.
Revenues from refined product pipelines increased by $9.2 million from $63.4 million for the year
ended December 31, 2006 to $72.6 million for the year ended December 31, 2007. This increase in
refined product pipeline revenue was principally due to an increase in volumes shipped on our
refined product pipelines, the effect of the annual tariff increase on refined product shipments,
and the realization of $3.1 million of previously deferred revenue. Shipments on our refined
product pipelines averaged 140.2 thousand barrels per day (mbpd) for the year ended December 31,
2007 as compared to 131.9 mbpd for the year ended December 31, 2006.
Revenues from the intermediate pipelines increased by $3.0 million from $10.7 million for the year
ended December 31, 2006 to $13.7 million for the year ended December 31, 2007. This increase in
intermediate pipeline revenue was principally due to an increase in volumes shipped on our
intermediate pipelines, the effect of the annual tariff increase on intermediate pipeline shipments
and an increase in previously deferred revenue realized. Intermediate pipeline revenue for the
year ended December 31, 2007 included $2.4 million, as compared to $1.0 million for the year ended
December 31, 2006, of previously deferred revenue. Shipments on the Intermediate Pipelines
averaged 65.0 mbpd for the year ended December 31, 2007 as compared to 57.7 mbpd for the year ended
December 31, 2006.
Revenues from terminal and truck loading rack service fees increased by $1.3 million from $15.1
million for the year ended December 31, 2006 to $16.4 million for the year ended December 31, 2007.
This increase was principally due to an increase in refined products terminalled in our
facilities. Refined products terminalled in our facilities averaged 165.4 mbpd for the year ended
December 31, 2007 as compared to 161.5 mbpd for the year ended December 31, 2006.
- 43 -
Other revenues for the year ended December 31, 2007 consisted of $2.7 million related to the sale
of inventory of accumulated terminal overages of refined product to Holly. These overages arose
from net product gains at our terminals from the beginning of 2005 through the third quarter of
2007. We have negotiated an amendment to our pipelines and terminals agreement with Holly that
provides that such terminal overages of refined product shall belong to Holly in the future. There
were no other revenues for the year ended December 31, 2006.
Operations Expense
Operations expense increased $4.3 million from the year ended December 31, 2006 to the year ended
December 31, 2007. This increase in expense was principally due to higher throughput volumes, an
increase in pipeline and terminal maintenance expense and an increase in the cost of employees who
perform services for us, including the addition of two new senior level executives.
Depreciation and Amortization
Depreciation and amortization decreased by $0.9 million from the year ended December 31, 2006 to
the year ended December 31, 2007, due principally to a reduction in amortization expense, as a
transportation agreement became fully amortized in April 2007.
General and Administrative
General and administrative costs increased by $0.2 million from the year ended December 31, 2006 to
the year ended December 31, 2007, due principally to an increase in equity-based incentive
compensation expense.
Interest Expense
Interest expense for the year ended December 31, 2007 totaled $13.3 million, an increase of $0.2
million from $13.1 million for the year ended December 31, 2006. For the year ended December 31,
2007, interest expense consisted of: $11.9 million of interest on the outstanding debt, net of the
impact of the interest rate swap; $0.4 million of commitment fees on the unused portion of the
Credit Agreement; and $1.0 million of amortization of the discount on the Senior Notes and deferred
debt issuance costs. For the year ended December 31, 2006, interest expense consisted of: $11.6
million of interest on the outstanding debt, net of the impact of the interest rate swap; $0.5
million of commitment fees on the unused portion of the Credit Agreement; and $1.0 million of
amortization of the discount on the Senior Notes and deferred debt issuance costs.
Minority Interest in Earnings of Rio Grande
The minority interest related to the 30% of Rio Grande that we do not own reduced our income by
$1.1 for the year ended December 31, 2007 as compared to $0.7 million for the year ended December
31, 2006.
State Income Tax
In May 2006, the State of Texas enacted a bill that replaced the existing franchise tax with a
margin tax. Effective January 1, 2007, the margin tax applies to legal entities conducting
business in Texas, including previously non-taxable entities such as limited partnerships and
limited liability partnerships. The margin tax is based on our Texas sourced taxable margin. The
tax is calculated by applying a tax rate to a base that considers both revenues and expenses and
therefore has the characteristics of an income tax. As a result, we recorded $0.3 million in state
income tax for the year ended December 31, 2007 that is solely attributable to the Texas margin
tax. There was no comparable state income tax for the year ended December 31, 2006.
- 44 -
Results of Operations Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Summary
Net income was $27.5 million for the year ended December 31, 2006, an increase of $0.7 million from
$26.8 million for the year ended December 31, 2005. The increase in overall earnings was
principally due to the earnings generated from the Intermediate Pipelines acquired from Holly on
July 8, 2005, for which we realized earnings for only six months in 2005, and increases in volumes
transported by affiliates on our intermediate and refined product pipeline systems following
Hollys completion in June 2006 of an expansion of the Navajo Refinery. Also favorably impacting
earnings in 2006 were the effects of the annual tariff increases on our pipelines and the
recognition of certain previously deferred revenue. Partially offsetting these positive factors
was a reduction of volumes transported and terminalled in the second quarter of 2006 due to
significant refinery downtime experienced by all of the refineries utilizing our refined product
distribution network (described below) and higher interest expense principally related to the
senior notes issued in connection with the pipeline and terminal assets acquired from Alon in early
2005 and the Intermediate Pipelines acquired from Holly in July 2005.
Revenues
Revenues of $89.2 million for the year ended December 31, 2006 were $9.1 million greater than the
$80.1 million for the comparable period of 2005. This increase was principally due to an increase
in volumes transported on the pipeline and terminal assets acquired from Alon in early 2005 and the
Intermediate Pipelines acquired from Holly in July 2005, for which we realized revenues for only
ten and six of the twelve months of 2005, respectively. Additionally, favorably impacting revenues
for the year ended December 31, 2006 was the recognition of certain previously deferred revenue, an
increase in volumes transported by affiliates following the Navajo Refinery expansion, and the
effects of the annual tariff increases on our pipelines. Partially offsetting these increases, was
a reduction of volumes transported and terminalled in the second quarter of 2006 due to significant
refinery downtime experienced by all of the refineries utilizing our refined product distribution
network as discussed below. Also impacting revenue for the year ended December 31, 2006, BP
completed its obligation to pay the border crossing fee under BPs Rio Grande Pipeline contract in
2005. We did not have border crossing fee revenues for the year ended December 31, 2006, due to
the fulfillment of this contract.
Refineries served by our product distribution network incurred significant downtime during the
second quarter of 2006. Refiners were generally required to start producing ULSD fuel by June
2006. To meet this requirement, many refiners, including Hollys Navajo Refinery and Alons Big
Spring Refinery, required downtime at their refineries so that ULSD-associated projects could be
brought on line. Additionally, Holly completed an expansion of the Navajo Refinery during this
period of downtime which resulted in additional unit downtime. The tie-in of these new projects
coming on line, combined with other refinery maintenance, much of which was timed in conjunction
with the capital projects, resulted in reduced refinery production, which was the principal factor
contributing to a significant volume decrease during the second quarter of 2006.
Revenues from refined product pipelines increased by $2.7 million from $60.7 million for the year
ended December 31, 2005 to $63.4 million for the year ended December 31, 2006. Shipments on our
refined product pipelines averaged 131.9 mbpd for the year ended December 31, 2006 as compared to
131.3 mbpd for the year ended December 31, 2005. Refined product pipeline revenues for the year
ended December 31, 2006 were negatively impacted due to BPs completion of its border crossing fee
obligations under BPs Rio Grande Pipeline contract in early 2005. We had no border crossing fee
revenues for the year ended December 31, 2006 as compared to $0.8 million in 2005 due to the
fulfillment of this contract.
Revenues from the intermediate pipelines increased by $6.1 million from $4.6 million for the year
ended December 31, 2005 to $10.7 million for the year ended December 31, 2006. This increase
includes $1.0 million attributable to the recognition of previously deferred revenue as the
contractual period for us to
- 45 -
provide certain pipeline services had expired. Shipments on the Intermediate Pipelines averaged
57.7 mbpd for the year ended December 31, 2006 as compared to 28.3 mbpd for the year ended December
31, 2005. The increase was principally due to realizing revenues for a full twelve months of
volumes during the year ended December 31, 2006, while we realized revenues for only six months
during the year ended December 31, 2005.
Revenues from terminal and truck loading rack service fees increased by $0.4 million from $14.7
million for the year ended December 31, 2005 to $15.1 million for the year ended December 31, 2006,
principally due to rates increases in terminal fees charged to our affiliates. Refined products
terminalled in our facilities for the comparable periods decreased to 161.5 mbpd in the year ended
December 31, 2006 from 163.1 mbpd in the year ended December 31, 2005.
Operations Expense
Operations expense increased $3.3 million from the year ended December 31, 2005 to the year ended
December 31, 2006. This increase in expense was principally due to $2.2 million of increased
direct operating costs relating to the assets acquired from Alon and direct operating costs of $0.7
million for the Intermediate Pipelines that were acquired in July 2005. Additionally impacting
operations expense were other year-over-year increases in pipeline and terminal maintenance expense
and direct operating costs relating to the personnel who support our operations.
Depreciation and Amortization
Depreciation and amortization was $1.1 million higher in the year ended December 31, 2006 than in
the year ended December 31, 2005, due principally to the increase in depreciation from the pipeline
and terminal assets acquired from Alon in 2005.
General and Administrative
General and administrative costs were $4.9 million for the year ended December 31, 2006, an
increase of $0.9 million from $4.0 million for the year ended December 31, 2005 due mainly to
equity-based compensation expense and business development costs.
Interest Expense
Interest expense for the year ended December 31, 2006 totaled $13.1 million, an increase of $3.5
million from $9.6 million for the year ended December 31, 2005. The increase is due to the debt
issued in connection with the Alon and Intermediate Pipelines acquisitions. In the year ended
December 31, 2006, interest expense consisted of: $11.6 million of interest on the outstanding
debt, net of the impact of the interest rate swap; $0.5 million of commitment fees on the unused
portion of the Credit Agreement; and $1.0 million of amortization of the discount on the Senior
Notes and deferred debt issuance costs. In the year ended December 31, 2005, interest expense
consisted of: $8.4 million of interest on the outstanding debt, net of the impact of the interest
rate swap; $0.4 million of commitment fees on the unused portion of the Credit Agreement; and $0.8
million of amortization of the discount on the Senior Notes and deferred debt issuance costs.
Minority Interest in Earnings of Rio Grande
The minority interest related to the 30% of Rio Grande that we do not own for the year ended
December 31, 2006 was comparable to the year ended December 31, 2005. The minority interest in Rio
Grande reduced our income by $0.7 million for the years ended December 31, 2006 and 2005.
- 46 -
LIQUIDITY AND CAPITAL RESOURCES
Overview
In August 2007, we entered into an amended and restated four-year, $100.0 million senior secured
revolving Credit Agreement expiring in August 2011 that amends and restates our previous senior
credit agreement in its entirety. Union Bank of California, N.A. is one of the lenders and serves
as administrative agent under this agreement. The Credit Agreement is available to fund capital
expenditures, acquisitions, and working capital and for general partnership purposes. As of
December 31, 2007 and December 31, 2006, we had no amounts outstanding under the Credit Agreement.
We financed the $120.0 million cash portion of the consideration for the Alon transaction through
our private offering on February 28, 2005 of $150.0 million of 6.25% Senior Notes due 2015. We
used the balance to repay $30.0 million of outstanding indebtedness under our Credit Agreement,
including $5.0 million drawn shortly before the closing of the Alon transaction. We financed a
portion of the cash consideration for the Intermediate Pipelines transaction with the private
offering in June 2005 of an additional $35.0 million in principal amount of the Senior Notes. On
July 28, 2005, we filed a registration statement to allow the holders of the Senior Notes to
exchange the Senior Notes for exchange notes registered with the SEC with substantially identical
terms, which exchange was completed in October 2005.
We financed a portion of the cash consideration paid for the Intermediate Pipelines with $45.1
million of proceeds raised from the private sale of 1,100,000 of our common units to a limited
number of institutional investors which closed simultaneously with the closing of the acquisition
of the Intermediate Pipelines on July 8, 2005. On September 2, 2005, we filed a registration
statement with the SEC using a shelf registration process which allows the institutional
investors to freely transfer their units. Additionally under this shelf process, we may offer from
time to time up to $800.0 million of our securities, through one or more prospectus supplements
that would describe, among other things, the specific amounts, prices and terms of any securities
offered and how the proceeds would be used. Any proceeds from the sale of securities would be used
for general business purposes, which may include, among other things, funding acquisitions of
assets or businesses, working capital, capital expenditures, investments in subsidiaries, the
retirement of existing debt and/or the repurchase of common units or other securities.
We believe our current cash balances, future internally-generated funds and funds available under
our Credit Agreement will provide sufficient resources to meet our working capital liquidity needs
for the foreseeable future. In February, May, August and November 2007, we paid regular quarterly
cash distributions of $0.675, $0.69, $0.705 and $0.715, respectively, on all units, an aggregate
amount of $48.0 million. Included in these distributions was an aggregate of $2.2 million paid to
the general partner as incentive distributions, as the quarterly distributions per unit exceeded
the target distribution amount of $0.55.
Cash and cash equivalents decreased by $1.2 million during the year ended December 31, 2007. The
cash flows used for financing activities of $50.7 million and cash flows used for investing
activities of $9.6 million, exceeded cash flows generated from operating activities of $59.1
million. Working capital decreased by $4.0 million to $5.4 million during the year ended December
31, 2007.
Cash Flows Operating Activities
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Cash flows from operating activities increased by $13.2 million from $45.9 million for the year
ended December 31, 2006 to $59.1 million for the year ended December 31, 2007. This increase is
principally due to $14.8 million in additional cash collections from our major customers, resulting
principally from increased revenues and shortfall billings, partially offset by miscellaneous
year-over-year changes in collections and payments.
As discussed above, our major shippers are obligated to make deficiency payments to us if we do not
receive certain minimum revenue payments. Certain of these shippers then have the right to
recapture
- 47 -
these amounts if future volumes exceed minimum levels. For the year ended December 31, 2007, we
received cash payments of $4.6 million under these commitments. We billed $5.5 million during the
year ended December 31, 2006 related to shortfalls that occurred in 2006, of which $5.5 million
expired without recapture and was recognized as revenue in the year ended December 31, 2007.
Another $0.4 million is included in our accounts receivable at December 31, 2007 related to
shortfalls that occurred in the fourth quarter of 2007.
Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Cash flows from operating activities increased by $3.3 million from $42.6 million for the year
ended December 31, 2005 to $45.9 million for the year ended December 31, 2006. This increase is
principally due to $13.5 million additional cash collections from customers on the Alon assets and
Intermediate Pipelines purchased in 2005. This increase of cash collections is partially offset by
increased operations expense of $2.8 million on these new assets and increased cash payments for
interest of $7.1 million, principally on the debt issued for these acquisitions. The remaining
decrease in cash flows from operating activities is due to miscellaneous year-over-year changes in
collections and payments, offset by lower pre-payments in 2006.
For the year ended December 31, 2006, we received cash payments of $5.6 million under minimum
revenue commitments, of which $0.9 million was recaptured in 2006. We billed $1.0 million during
the year ended December 31, 2005 related to shortfalls that occurred in 2005, which expired without
recapture and was recognized as revenue in the year ended December 31, 2006. Another $1.3 million
is included in our accounts receivable at December 31, 2006 related to shortfalls that occurred in
the fourth quarter of 2006.
Cash Flows Investing Activities
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Cash flows used for investing activities increased by $0.5 million from $9.1 million for the year
ended December 31, 2006 to $9.6 million for the year ended December 31, 2007. Additions to
properties and equipment for the year ended December 31, 2007 was $10.0 million, an increase of
$0.9 million from $9.1 million for the year ended December 31, 2006. During the year ended
December 31, 2007, we also received cash proceeds of $0.3 million related to the sale of certain
assets.
Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Cash flows used for investing activities decreased by $122.7 million from $131.8 million for the
year ended December 31, 2005 to $9.1 million for the year ended December 31, 2006. On February 28,
2005, we closed on the Alon transaction which required $120.0 million in cash plus transaction
costs of $2.0 million. Additionally, we issued 937,500 Class B subordinated units valued at $24.7
million to Alon as part of the consideration. See Alon Transaction below for additional
information. On July 8, 2005, we closed on the acquisition of the Holly Intermediate Pipelines for
$81.5 million, which consisted of $77.7 million in cash, 70,000 common units of HEP and a capital
account credit of $1.0 million to maintain Hollys existing general partner interest in the
Partnership. As this was a transaction between entities under common control, we recorded the
acquired assets at Hollys historic book value. This resulted in payment to Holly of a purchase
price of $71.9 million in excess of the basis of the assets received, which is included in cash
flows from financing activities. See Holly Intermediate Pipelines Transaction below for
additional information. Additions to properties and equipment for the year ended December 31, 2006
was $9.1 million, an increase of $5.2 million from $3.9 million for the year ended December 31,
2005.
Cash Flows Financing Activities
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
Cash flows used for financing activities increased by $4.9 million from $45.8 million for the year
ended December 31, 2006 to $50.7 million for the ended December 31, 2007. During the year ended
December 31, 2007, we paid cash distributions on all units and the general partner interest in the
aggregate amount of $48.0 million, an increase of $4.3 million from $43.7 million in distributions
paid during the year ended December 31, 2006. Cash distributions paid to the minority interest
owner in Rio Grande was $1.3 million
- 48 -
for the year ended December 31, 2007, a decrease of $0.2 million from $1.5 million in distributions
paid for the year ended December 31, 2006. Cash paid for the purchase of our common units for
restricted grants was $1.1 million for the year ended December 31, 2007, an increase of $0.5
million from $0.6 million for the year ended December 31, 2006. Also for the year ended December
31, 2007, we paid $0.3 million in deferred financing costs that were attributable to the amendment
to our Credit Agreement.
Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Cash flows used for financing activities increased by $136.4 million to $45.8 million for the year
ended December 31, 2006. This compared to cash flows provided by financing activities of $90.6
million for the year ended December 31, 2005. In February 2005, we received proceeds of $147.4
million from the issuance of Senior Notes in connection with the Alon asset acquisition.
Additionally, we used proceeds from the original Senior Note offering to repay $30.0 million of
outstanding indebtedness under our Credit Agreement, including $5.0 million drawn shortly before
the closing of the Alon transaction. In June 2005, in anticipation of the July Holly Intermediate
Pipelines transaction, we received additional proceeds from Senior Notes issued of $33.8 million.
See Senior Notes Due 2015 below for additional information. We financed a portion of the cash
consideration paid for the Intermediate Pipelines with $45.1 million of proceeds raised from the
private sale of 1,100,000 of our common units to a limited number of institutional investors which
closed simultaneously with the closing of the acquisition of the Intermediate Pipelines on July 8,
2005. During the year ended December 31, 2006, we paid cash distributions on all units and the
general partner interest in the aggregate amount of $43.7 million, an increase of $8.7 million from
$35.0 million in distributions paid during the year ended December 31, 2005. Cash distributions
paid to the minority interest owner in Rio Grande was $1.5 million for the year ended December 31,
2006, a decrease of $0.7 million from $2.2 million for the year months ended December 31, 2005.
Cash paid for the purchase of our common units for restricted grants was $0.6 million for each of
the years ended December 31, 2006 and 2005. Also for the year ended December 31, 2005, we received
an additional $0.6 million capital contribution from our general partner and paid $1.2 million in
deferred debt issuance costs.
Capital Requirements
Our pipeline and terminalling operations are capital intensive, requiring investments to maintain,
expand, upgrade or enhance existing operations and to meet environmental and operational
regulations. Our capital requirements have consisted of, and are expected to continue to consist
of, maintenance capital expenditures and expansion capital expenditures. Maintenance capital
expenditures represent capital expenditures to replace partially or fully depreciated assets to
maintain the operating capacity of existing assets. Maintenance capital expenditures include
expenditures required to maintain equipment reliability, tankage and pipeline integrity, and safety
and to address environmental regulations. Expansion capital expenditures represent capital
expenditures to expand the operating capacity of existing or new assets, whether through
construction or acquisition. Expansion capital expenditures include expenditures to acquire assets
to grow our business and to expand existing facilities, such as projects that increase throughput
capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with
existing assets that are minor in nature and do not extend the useful life of existing assets are
charged to operating expenses as incurred.
Each year the HLS board of directors approves our annual capital budget, which specifies capital
projects that our management is authorized to undertake. Additionally, at times when conditions
warrant or as new opportunities arise, special projects may be approved. The funds allocated to a
particular capital project may be expended over a period in excess of a year, depending on the time
required to complete 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.
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we
have agreed to expand our South System between Artesia, New Mexico and El Paso, Texas. The
expansion of the South System will include replacing 85 miles of 8-inch pipe with 12-inch pipe,
adding 150,000 barrels of refined product storage at our El Paso Terminal, improving existing
pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and Phoenix, Arizona, and making
related modifications.
- 49 -
The cost of this project is estimated to be $48.3 million. Currently, we are expecting to complete
this project by January 2009. The agreement also provides for a tariff increase, expected to be
effective May 1, 2008, on Holly shipments on our refined product pipelines.
In November 2007, we announced an agreement in principle for the acquisition of certain
pipeline and tankage assets from Holly for approximately $180.0 million. The consideration is
expected to consist of $171.0 million in cash and our common units valued at approximately $9.0
million. The assets include 136 miles of crude oil trunk lines that deliver crude to Hollys
Navajo Refinery in southeast New Mexico, approximately 725 miles of gathering and connection
pipelines located in west Texas and New Mexico, on-site crude tankage having a combined 600,000
barrels of storage capacity located within the Navajo and Woods Cross refinery complexes, a jet
fuel products pipeline and terminal (terminal leased through September 2011) between Artesia and
Roswell, New Mexico, and 10 miles of crude oil and product pipelines that support Hollys Woods
Cross Refinery. In connection with the closing of this proposed transaction, we intend to enter
into a 15-year pipelines and tankage agreement with Holly that will contain a minimum annual
revenue commitment to us from Holly. Both the HLS and Holly boards of directors have approved this
proposed transaction, which we expect to close in the first quarter of 2008.
In November 2007, we executed a definitive agreement with Plains to acquire a 25% joint venture
interest in a new 95-mile intrastate pipeline system now under construction by Plains, for the
shipment of up to 120,000 bpd of crude oil into the Salt Lake City area. Under the agreement, the
SLC Pipeline will be owned by a joint venture company which will be owned 75% by Plains and 25% by
us. Subject to the actual cost of the SLC Pipeline, we will purchase our 25% interest in the joint
venture for an amount between $22.0 and $25.5 million in the second quarter of 2008, when the SLC
Pipeline is expected to become fully operational. The SLC Pipeline will allow various refiners in
the Salt Lake City area, including Hollys Woods Cross refinery, to ship crude oil into the Salt
Lake City area from the Utah terminus of the Frontier Pipeline as well as crude oil from Wyoming
and Utah, which is currently flowing on Plains Rocky Mountain Pipeline.
On January 31, 2008, we entered into an option agreement with Holly, granting us an option to
purchase all of Hollys equity interests in a joint venture pipeline currently under construction.
The pipeline will be capable of transporting refined petroleum products from Salt Lake City, Utah
to Las Vegas, Nevada. Holly currently owns 75% of the equity interests in
the UNEV Pipeline. Under this agreement, we have an option to purchase Hollys equity interests
in the UNEV Pipeline, effective for a 180-day period commencing when the UNEV Pipeline
becomes operational, at a purchase price equal to Hollys investment in the joint venture pipeline,
plus interest at 7% per annum. The initial capacity of the
pipeline will be 62,000 bpd, with the capacity for further expansion to 120,000 bpd. The total
cost of the pipeline project including terminals is expected to be $300.0 million. Hollys share
of this cost is $225.0 million. Construction of this project is currently expected to be completed
and operational in mid 2009.
We are also studying several other projects, which are in various stages of analysis.
We expect that our currently planned expenditures for sustaining and maintenance capital as well as
expenditures for capital development projects such as the UNEV Pipeline, SLC Pipeline and South
System expansion projects described above will be funded with existing cash balances, cash
generated by operations, the sale of additional limited partner units and advances under our Credit
Agreement.
Additionally, we plan to upsize our Credit Agreement to fund the cash portion of the consideration
for our announced purchase of certain pipeline and tankage assets from Holly described above.
Credit Agreement
In August 2007, we entered into an amended and restated four-year, $100.0 million senior secured
revolving credit agreement expiring in August 2011 that amends and restates our previous senior
credit agreement in its entirety. Union Bank of California, N.A. is a lender and serves as
administrative agent under this agreement. The Credit Agreement is available to fund capital
expenditures, acquisitions, and working capital and for general partnership purposes. Advances
under the Credit Agreement that are
- 50 -
designated for working capital are short-term liabilities. Other advances under the Credit
Agreement are classified as long-term liabilities. In addition, the Credit Agreement is available
to fund letters of credit up to a $50.0 million sub-limit. Up to $20.0 million is available to
fund distributions to unitholders. As of December 31, 2007, we had no amounts outstanding under
the Credit Agreement.
We have the right to request an increase in the maximum amount of the Credit Agreement, up to
$200.0 million. Such request will become effective if (a) certain conditions specified in the
Credit Agreement are met and (b) existing lenders under the Credit Agreement or other financial
institutions reasonably acceptable to the administrative agent commit to lend such increased
amounts under the agreement.
Our obligations under the Credit Agreement are secured by substantially all of our assets.
Indebtedness under the Credit Agreement is recourse to our general partner and guaranteed by our
wholly-owned subsidiaries.
We may prepay all loans at any time without penalty, except for payment of certain breakage and
related costs. We are required to reduce all working capital borrowings under the Credit Agreement
to zero for a period of at least 15 consecutive days once each twelve-month period prior to the
maturity date of the agreement.
Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference
rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to
1.50%) or (b) at a rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable
margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio
of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes,
depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on
the unused portion of the Credit Agreement at a rate ranging from 0.20% or 0.50% based upon the
ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. The
agreement matures in August 2011. At that time, the agreement will terminate and all outstanding
amounts thereunder will be due and payable.
The Credit Agreement imposes certain requirements, including: a prohibition against distribution to
unitholders if, before or after the distribution, a potential default or an event of default as
defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire
other companies, change the nature of our business, enter a merger or consolidation, or sell
assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio and
debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able
to accelerate the maturity of the debt and exercise other rights and remedies.
Senior Notes Due 2015
Our Senior Notes mature on March 1, 2015 and bear interest at 6.25%. The Senior Notes are
unsecured and impose certain restrictive covenants, including limitations on our ability to incur
additional indebtedness, make investments, sell assets, incur certain liens, pay distributions,
enter into transactions with affiliates, and enter into mergers. 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.
The $185.0 million principal amount of Senior Notes is recorded at $181.4 million on our
accompanying consolidated balance sheet at December 31, 2007. The difference of $3.6 million is
due to the $2.7 million unamortized discount and $0.9 million relating to the fair value of the
interest rate swap contract as further discussed under Risk Management.
- 51 -
The following table presents our long-term contractual obligations as of December 31, 2007.
|
|
The pipeline operating lease amounts below reflect the exercise of the first of three
10-year extensions, effective July 2007, 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 are likely to be exercised. |
|
|
Most of our right of way agreements are renewable on an annual basis, and the right of way
lease payments below include only obligations under the remaining non-cancelable terms of
these agreements at December 31, 2007. For the foreseeable future, we intend to continue
renewing these agreements and expect to incur right of way expenses in addition to the
payments listed below. |
|
|
In consideration for Hollys assistance in obtaining our joint venture opportunity in the
SLC Pipeline discussed under Capital Requirements, we will pay Holly a $2.5 million finders
fee upon the closing of our investment in the joint venture with Plains. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
|
|
|
|
|
|
Less than |
|
|
|
|
|
|
|
|
|
|
Over 5 |
|
|
|
Total |
|
|
1 Year |
|
|
2-3 Years |
|
|
4-5 Years |
|
|
Years |
|
|
|
(In thousands) |
|
Long-term debt principal |
|
$ |
185,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
185,000 |
|
Long-term debt interest |
|
|
86,719 |
|
|
|
11,563 |
|
|
|
23,125 |
|
|
|
23,125 |
|
|
|
28,906 |
|
Pipeline operating lease |
|
|
55,625 |
|
|
|
5,855 |
|
|
|
11,711 |
|
|
|
11,711 |
|
|
|
26,348 |
|
Right of way leases |
|
|
1,646 |
|
|
|
497 |
|
|
|
161 |
|
|
|
82 |
|
|
|
906 |
|
Other |
|
|
23,724 |
|
|
|
5,066 |
|
|
|
4,841 |
|
|
|
4,367 |
|
|
|
9,450 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
352,714 |
|
|
$ |
22,981 |
|
|
$ |
39,838 |
|
|
$ |
39,285 |
|
|
$ |
250,610 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2007, 2006 and 2005.
A substantial majority of our revenues are generated under long-term contracts that include the
right to increase our rates and minimum revenue guarantees annually for increases in the PPI.
Historically, the PPI has increased an average of 3.7% annually over the past 5 calendar years.
Environmental Matters
Our operation of pipelines, terminals, and associated facilities in connection with the storage and
transportation of refined products is subject to stringent and complex federal, state, and local
laws and regulations governing the discharge of materials into the environment, or otherwise
relating to the protection of the environment. For additional discussion on environmental matter,
please see Environmental Regulation and Remediation under Item 1, Business.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition and results of operations are based upon our
consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States. The preparation of these financial statements
requires us to make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as
of the date of the financial statements. Actual results may differ from these estimates under
different assumptions or conditions. We consider the following policies to be the most critical to
understanding the judgments that are involved and the uncertainties that could impact our results
of operations, financial condition and cash flows.
- 52 -
Revenue Recognition
Revenues are recognized as products are shipped through our pipelines and terminals. Additional
pipeline transportation revenues result from an operating lease by Alon USA, L.P. of an interest in
the capacity of one of our pipelines.
Billings to customers for obligations under their quarterly minimum revenue commitments are
recorded as deferred revenue liabilities if the customer has the right to receive future services
for these billings. The revenue is recognized at the earlier of:
|
|
the customer receives the future services provided by these billings, |
|
|
the period in which the customer is contractually allowed to receive the services expires,
or |
|
|
we determine a high likelihood that we will not be required to provide services within the
allowed period. |
We recognize shortfall billings as revenue prior to the expiration of the contractual term period
to provide services only when we determine with a high likelihood that we will not be required to
provide services within the allowed period. We determine this when based on current and projected
shipping levels, that our pipeline systems will not have the necessary capacity to enable a
customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit
within its respective contractual shortfall make up period and 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. No impairments of long-lived assets were recorded during the
years ended December 31, 2007, 2006 and 2005.
Contingencies
It is common in our industry to be subject to proceedings, lawsuits and other claims related to
environmental, labor, product and other matters. We are required to assess the likelihood of any
adverse judgments or outcomes to these types of matters as well as potential ranges of probable
losses. A determination of the amount of reserves required, if any, for these types of
contingencies is made after careful analysis of each individual issue. The required reserves may
change in the future due to developments in each matter or changes in approach such as a change in
settlement strategy in dealing with these potential matters.
Recent Accounting Pronouncements
Interpretation No. 48 Accounting for Uncertainty in Income Taxes
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes.
This interpretation clarifies the accounting for uncertainty in income taxes recognized in an
enterprises financial statements by prescribing a recognition threshold and measurement attribute
for the financial statement recognition and measurement of a tax position taken or expected to be
taken in a tax return. This interpretation also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods, disclosure and transition.
This interpretation is effective for fiscal years
- 53 -
beginning after December 15, 2006. We adopted this standard effective January 1, 2007. The
adoption of this standard did not have a material impact on our financial condition, results of
operations and cash flows.
Statement of Financial Accounting Standards (SFAS) No. 157 Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This standard simplifies
and codifies guidance on fair value measurements under generally accepted accounting principles.
This standard defines fair value, establishes a framework for measuring fair value and prescribes
expanded disclosures about fair value measurements. This standard is effective for fiscal years
beginning after November 15, 2007. We do not anticipate that the adoption of this standard will
have a material effect on our financial condition, results of operations and cash flows.
SFAS No. 133 Implementation Issue No. E23 Issues Involving the Application of the Shortcut Method
under Paragraph 68
In January 2008, the FASB posted SFAS No. 133 Implementation Issue No. E23, Issues Involving the
Application of the Shortcut Method under Paragraph 68. This standard addresses issues pertaining
to the application of the shortcut method in accounting for hedges when the settlement of a hedged
item occurs subsequent to the interest rate swap trade date. It also addresses hedging
relationships when the transaction price of an interest rate swap is zero. This standard is
effective for hedging relationships designated on or after January 1, 2008 and requires the
reassessment of preexisting hedges utilizing the shortcut method under this new guidance. While we
are currently evaluating this standard, we do not anticipate that the adoption of this standard
will have a material effect on our financial condition, results of operations and cash flows.
RISK MANAGEMENT
We have entered into an interest rate swap contract to effectively convert the interest expense
associated with $60.0 million of our 6.25% Senior Notes from a fixed rate to variable rates. Under
the swap agreement, we receive 6.25% fixed rate on the notional amount and pay a variable rate
equal to three month LIBOR plus an applicable margin of 1.1575%. The variable rate being paid on
the notional amount at December 31, 2007 was 6.281%, including the applicable margin. The maturity
of the swap contract is March 1, 2015, matching the maturity of the Senior Notes.
This interest rate swap has been designated as a fair value hedge as defined by SFAS No. 133. Our
interest rate swap meets the conditions required to assume no ineffectiveness under SFAS No. 133
and, therefore, we have used the shortcut method of accounting prescribed for fair value hedges
by SFAS No. 133. Accordingly, we adjust the carrying value of the swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair
value is being hedged. We record interest expense equal to the variable rate payments under the
swaps.
The fair value of the interest rate swap agreement of $0.9 million is included in Other long-term
liabilities in our accompanying consolidated balance sheet at December 31, 2007. The offsetting
entry to adjust the carrying value of the debt securities whose fair value is being hedged is
recognized as a reduction of Long-term debt on our accompanying consolidated balance sheet at
December 31, 2007.
The market risk inherent in our debt instruments and positions is the potential change arising from
increases or decreases in interest rates as discussed below.
At December 31, 2007, we had an outstanding principal balance on our Senior Notes of $185.0
million. By means of our interest rate swap contract, we have effectively converted $60.0 million
of the Senior Notes from a fixed rate to variable rate. For the fixed rate debt portion of $125.0
million, changes in interest rates would generally affect the fair value of the debt, but not our
earnings or cash flows. Conversely, for the variable rate debt portion of $60.0 million, changes
in interest rates would generally not impact the fair value of the debt, but may affect our future
earnings and cash flows. We estimate a hypothetical 10% change in the yield-to-maturity applicable
to our fixed rate debt portion of $125.0 million as of December 31, 2007 would result in a change
of approximately $4.9 million in the fair value of the debt. A hypothetical 10% change in the
interest rate applicable to our variable rate debt portion of $60.0 million would not have a
material effect on our earnings or cash flows.
- 54 -
At December 31, 2007, 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 to any
significant degree 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.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. See Risk
Management under Managements Discussion and Analysis of Financial Condition and Results of
Operations for a discussion of market risk exposures that we have with respect to our cash and
cash equivalents and long-term debt. We utilize derivative instruments to hedge our interest rate
exposure, also discussed under Risk Management.
Since we do not own products shipped on our pipelines or terminalled at our terminal facilities we
do not have market risks associated with commodity prices.
- 55 -
Item 8. Financial Statements and Supplementary Data
MANAGEMENTS REPORT ON ITS ASSESSMENT OF THE COMPANYS INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Holly Energy Partners, L.P. (the Partnership) is responsible for establishing and
maintaining adequate internal control over financial reporting.
All internal control systems, no matter how well designed, have inherent limitations. Therefore,
even those systems determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation.
Management assessed the Partnerships internal control over financial reporting as of December 31,
2007 using the criteria for effective control over financial reporting established in Internal
Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on this assessment, management believes that, as of December 31, 2007, 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,
2007. That report appears on page 57.
- 56 -
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 2007, 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, 2007, 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, 2007 and 2006, and the related consolidated statements of income, partners equity
(deficit), and cash flows for each of the three years in the period ended December 31, 2007 of
Holly Energy Partners, L.P. and our report dated February 14, 2008, expressed an unqualified
opinion thereon.
Dallas, Texas
February 14, 2008
- 57 -
Index to Consolidated Financial Statements
|
|
|
|
|
|
|
Page |
|
|
|
Reference |
|
|
|
|
59 |
|
|
|
|
|
|
|
|
|
60 |
|
|
|
|
|
|
|
|
|
61 |
|
|
|
|
|
|
|
|
|
62 |
|
|
|
|
|
|
|
|
|
63 |
|
|
|
|
|
|
|
|
|
64 |
|
- 58 -
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, 2007 and 2006, and the related consolidated statements of income,
partners equity (deficit), and cash flows for each of the three years in the period ended December
31, 2007. 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, 2007 and 2006, and the related consolidated results of its operations and its cash flows, for
each of the three years in the period ended December 31, 2007 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, 2007, 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 14, 2008 expressed an unqualified opinion thereon.
Dallas, Texas
February 14, 2008
- 59 -
Holly Energy Partners, L.P.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands, except unit data) |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
10,321 |
|
|
$ |
11,555 |
|
Accounts receivable: |
|
|
|
|
|
|
|
|
Trade |
|
|
6,611 |
|
|
|
7,339 |
|
Affiliates |
|
|
5,700 |
|
|
|
5,716 |
|
|
|
|
|
|
|
|
|
|
|
12,311 |
|
|
|
13,055 |
|
|
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
546 |
|
|
|
1,212 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
23,178 |
|
|
|
25,822 |
|
|
|
|
|
|
|
|
|
|
Properties and equipment, net |
|
|
158,600 |
|
|
|
160,484 |
|
Transportation agreements, net |
|
|
54,273 |
|
|
|
56,821 |
|
Other assets |
|
|
2,853 |
|
|
|
2,644 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
238,904 |
|
|
$ |
245,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
3,011 |
|
|
$ |
3,781 |
|
Accounts payable affiliates |
|
|
6,021 |
|
|
|
2,198 |
|
Accrued interest |
|
|
2,996 |
|
|
|
2,941 |
|
Deferred revenue |
|
|
3,700 |
|
|
|
5,486 |
|
Accrued property taxes |
|
|
1,177 |
|
|
|
868 |
|
Other current liabilities |
|
|
827 |
|
|
|
1,098 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
17,732 |
|
|
|
16,372 |
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
181,435 |
|
|
|
180,660 |
|
Other long-term liabilities |
|
|
1,181 |
|
|
|
1,550 |
|
Minority interest |
|
|
10,740 |
|
|
|
10,963 |
|
|
|
|
|
|
|
|
|
|
Partners equity (deficit): |
|
|
|
|
|
|
|
|
Common unitholders (8,170,000 units
issued and outstanding at December 31,
2007 and 2006) |
|
|
172,807 |
|
|
|
176,844 |
|
Subordinated unitholders (7,000,000 units
issued and outstanding at December 31,
2007 and 2006) |
|
|
(73,725 |
) |
|
|
(70,022 |
) |
Class B subordinated unitholders (937,500
units issued and outstanding at December
31, 2007 and 2006) |
|
|
22,973 |
|
|
|
23,469 |
|
General partner interest (2% interest) |
|
|
(94,239 |
) |
|
|
(94,065 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners equity |
|
|
27,816 |
|
|
|
36,226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity |
|
$ |
238,904 |
|
|
$ |
245,771 |
|
|
|
|
|
|
|
|
See accompanying notes.
- 60 -
Holly Energy Partners, L.P.
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands, except per unit data) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
60,961 |
|
|
$ |
52,878 |
|
|
$ |
44,184 |
|
Third parties |
|
|
41,698 |
|
|
|
36,316 |
|
|
|
35,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
102,659 |
|
|
|
89,194 |
|
|
|
80,120 |
|
Affiliates other |
|
|
2,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
105,407 |
|
|
|
89,194 |
|
|
|
80,120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
32,911 |
|
|
|
28,630 |
|
|
|
25,332 |
|
Depreciation and amortization |
|
|
14,382 |
|
|
|
15,330 |
|
|
|
14,201 |
|
General and administrative |
|
|
5,043 |
|
|
|
4,854 |
|
|
|
4,047 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52,336 |
|
|
|
48,814 |
|
|
|
43,580 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
53,071 |
|
|
|
40,380 |
|
|
|
36,540 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
533 |
|
|
|
899 |
|
|
|
649 |
|
Interest expense |
|
|
(13,289 |
) |
|
|
(13,056 |
) |
|
|
(9,633 |
) |
Gain on sale of assets |
|
|
298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,458 |
) |
|
|
(12,157 |
) |
|
|
(8,984 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before minority interest |
|
|
40,613 |
|
|
|
28,223 |
|
|
|
27,556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interest in Rio Grande Pipeline Company |
|
|
(1,067 |
) |
|
|
(680 |
) |
|
|
(740 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
39,546 |
|
|
|
27,543 |
|
|
|
26,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax |
|
|
(275 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
39,271 |
|
|
|
27,543 |
|
|
|
26,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less general partner interest in net income |
|
|
2,932 |
|
|
|
1,710 |
|
|
|
721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
36,339 |
|
|
$ |
25,833 |
|
|
$ |
26,095 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partners unit -
basic and diluted |
|
$ |
2.26 |
|
|
$ |
1.60 |
|
|
$ |
1.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited partners units
outstanding |
|
|
16,108 |
|
|
|
16,108 |
|
|
|
15,356 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
- 61 -
Holly Energy Partners, L.P.
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Cash flows from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
39,271 |
|
|
$ |
27,543 |
|
|
$ |
26,816 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
14,382 |
|
|
|
15,330 |
|
|
|
14,201 |
|
Minority interest in Rio Grande Pipeline Company |
|
|
1,067 |
|
|
|
680 |
|
|
|
740 |
|
Amortization of restricted and performance units |
|
|
1,375 |
|
|
|
927 |
|
|
|
207 |
|
Gain on sale of assets |
|
|
(298 |
) |
|
|
|
|
|
|
|
|
(Increase) decrease in current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
728 |
|
|
|
(4,263 |
) |
|
|
(2,338 |
) |
Accounts receivable affiliates |
|
|
16 |
|
|
|
(637 |
) |
|
|
(1,758 |
) |
Prepaid and other current assets |
|
|
666 |
|
|
|
115 |
|
|
|
(1,499 |
) |
Increase (decrease) in current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
|
(770 |
) |
|
|
761 |
|
|
|
1,305 |
|
Accounts payable affiliates |
|
|
3,823 |
|
|
|
764 |
|
|
|
164 |
|
Accrued interest |
|
|
55 |
|
|
|
49 |
|
|
|
2,840 |
|
Deferred revenue |
|
|
(1,786 |
) |
|
|
4,473 |
|
|
|
1,013 |
|
Accrued property taxes |
|
|
309 |
|
|
|
(144 |
) |
|
|
700 |
|
Other current liabilities |
|
|
(271 |
) |
|
|
(215 |
) |
|
|
(20 |
) |
Other, net |
|
|
489 |
|
|
|
470 |
|
|
|
257 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
59,056 |
|
|
|
45,853 |
|
|
|
42,628 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to properties and equipment |
|
|
(9,957 |
) |
|
|
(9,107 |
) |
|
|
(3,883 |
) |
Cash proceeds from sale of assets |
|
|
325 |
|
|
|
|
|
|
|
|
|
Acquisitions of pipeline and terminal assets |
|
|
|
|
|
|
|
|
|
|
(127,912 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used for investing activities |
|
|
(9,632 |
) |
|
|
(9,107 |
) |
|
|
(131,795 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of senior notes, net of discounts |
|
|
|
|
|
|
|
|
|
|
181,238 |
|
Proceeds from issuance of common units, net of underwriter
discount |
|
|
|
|
|
|
|
|
|
|
45,100 |
|
Excess purchase price over contributed basis of intermediate
pipelines |
|
|
|
|
|
|
|
|
|
|
(71,850 |
) |
Distributions to partners |
|
|
(47,974 |
) |
|
|
(43,670 |
) |
|
|
(35,022 |
) |
Repayment of revolving credit agreement |
|
|
|
|
|
|
|
|
|
|
(25,000 |
) |
Costs of issuing common units |
|
|
|
|
|
|
|
|
|
|
(349 |
) |
Deferred debt issuance costs |
|
|
|
|
|
|
|
|
|
|
(1,228 |
) |
Cash distributions to minority interest |
|
|
(1,290 |
) |
|
|
(1,470 |
) |
|
|
(2,220 |
) |
Cash contribution from general partner |
|
|
|
|
|
|
|
|
|
|
612 |
|
Purchase of units for restricted grants |
|
|
(1,082 |
) |
|
|
(634 |
) |
|
|
(635 |
) |
Deferred financing costs |
|
|
(296 |
) |
|
|
|
|
|
|
|
|
Other |
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used for) financing activities |
|
|
(50,658 |
) |
|
|
(45,774 |
) |
|
|
90,646 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) for the period |
|
|
(1,234 |
) |
|
|
(9,028 |
) |
|
|
1,479 |
|
Beginning of period |
|
|
11,555 |
|
|
|
20,583 |
|
|
|
19,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
$ |
10,321 |
|
|
$ |
11,555 |
|
|
$ |
20,583 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
- 62 -
Holly Energy Partners, L.P.
Consolidated Statements of Partners Equity (Deficit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Class B |
|
|
General |
|
|
|
|
|
|
Common |
|
|
Subordinated |
|
|
Subordinated |
|
|
Partner |
|
|
|
|
|
|
Units |
|
|
Units |
|
|
Units |
|
|
Interest |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
Balance December 31, 2004 |
|
$ |
144,318 |
|
|
$ |
(59,470 |
) |
|
$ |
|
|
|
$ |
(23,320 |
) |
|
$ |
61,528 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common units |
|
|
45,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,100 |
|
Cost of issuing common
units |
|
|
(349 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(349 |
) |
Issuance of Class B
subordinated units |
|
|
|
|
|
|
|
|
|
|
24,674 |
|
|
|
|
|
|
|
24,674 |
|
Capital contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,591 |
|
|
|
1,591 |
|
Distributions to partners |
|
|
(16,945 |
) |
|
|
(15,575 |
) |
|
|
(1,617 |
) |
|
|
(885 |
) |
|
|
(35,022 |
) |
Excess purchase price
over contributed basis
of intermediate
pipelines |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(71,850 |
) |
|
|
(71,850 |
) |
Purchase of units for
restricted grants |
|
|
(635 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(635 |
) |
Amortization of
restricted units |
|
|
207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
207 |
|
Net income |
|
|
12,872 |
|
|
|
11,892 |
|
|
|
1,331 |
|
|
|
721 |
|
|
|
26,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2005 |
|
|
184,568 |
|
|
|
(63,153 |
) |
|
|
24,388 |
|
|
|
(93,743 |
) |
|
|
52,060 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to partners |
|
|
(21,120 |
) |
|
|
(18,095 |
) |
|
|
(2,423 |
) |
|
|
(2,032 |
) |
|
|
(43,670 |
) |
Purchase of units for
restricted grants |
|
|
(634 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(634 |
) |
Amortization of
restricted units |
|
|
927 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
927 |
|
Net income |
|
|
13,103 |
|
|
|
11,226 |
|
|
|
1,504 |
|
|
|
1,710 |
|
|
|
27,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2006 |
|
|
176,844 |
|
|
|
(70,022 |
) |
|
|
23,469 |
|
|
|
(94,065 |
) |
|
|
36,226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to partners |
|
|
(22,762 |
) |
|
|
(19,495 |
) |
|
|
(2,611 |
) |
|
|
(3,106 |
) |
|
|
(47,974 |
) |
Purchase of units for
restricted grants |
|
|
(1,082 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,082 |
) |
Amortization of
restricted and
performance units |
|
|
1,375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,375 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
18,432 |
|
|
|
15,792 |
|
|
|
2,115 |
|
|
|
2,932 |
|
|
|
39,271 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007 |
|
$ |
172,807 |
|
|
$ |
(73,725 |
) |
|
$ |
22,973 |
|
|
$ |
(94,239 |
) |
|
$ |
27,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
- 63 -
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2007
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 45% 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 pipelines and terminal facilities.
One of Hollys wholly-owned subsidiaries owns a refinery in Artesia, New Mexico, which Holly
operates in conjunction with crude, vacuum distillation and other facilities situated in Lovington,
New Mexico (collectively, the Navajo Refinery). In July 2005, we acquired the two parallel
intermediate feedstock pipelines (the Intermediate Pipelines), which connect the New Mexico
refining facilities. The Navajo Refinery produces high-value refined products such as gasoline,
diesel fuel and jet fuel and serves markets in the southwestern United States and northern Mexico.
In conjunction with Hollys operation of the Navajo Refinery, we operate refined product pipelines
as part of the product distribution network of the Navajo Refinery. Our terminal operations
serving the Navajo Refinery include a truck rack at the Navajo Refinery and four integrated refined
product terminals located in New Mexico, Texas and Arizona.
Another of Hollys wholly-owned subsidiaries owns a refinery located near Salt Lake City, Utah (the
Woods Cross Refinery). Our operations serving the Woods Cross Refinery include a truck rack at
the Woods Cross Refinery, a refined product terminal in Spokane, Washington and a 50% non-operating
interest in product terminals in Boise and Burley, Idaho.
In February 2005, we acquired from Alon USA, Inc. and several of its wholly-owned subsidiaries
(collectively, Alon) four refined products pipelines, an associated tank farm and two refined
products terminals. These pipelines and terminals are located primarily in Texas and transport
light refined products for Alons refinery in Big Spring, Texas.
Additionally, we own a refined product terminal in Mountain Home, Idaho, and a 70% interest in Rio
Grande Pipeline Company (Rio Grande), which provides pipeline transportation of liquid petroleum
gases to northern Mexico.
Principles of Consolidation
The consolidated financial statements include our accounts and those of our subsidiaries and Rio
Grande. All significant inter-company transactions and balances have been eliminated. The
pipeline and terminal assets that were contributed to us from Holly concurrently with the
completion of our initial public offering in 2004, as well as the intermediate pipeline assets that
were purchased from Holly in July 2005 were accounted for as transactions among entities under
common control. Accordingly, these assets were recorded on our balance sheets at Hollys basis
instead of the purchase price or fair value.
If the assets acquired from Holly upon our formation and if the intermediate pipelines transaction
had been acquired from third parties, the cash payment upon formation of $125.6 million and the
excess of the intermediate pipeline purchase price over its basis of $71.9 million would have been
recorded as properties or intangible assets instead of reductions of partners equity. Also, the
subordinated units issued to Holly would have been recorded at fair value instead of the carryover
basis of the contributed assets.
- 64 -
Use of Estimates
The preparation of financial statements in accordance with U.S. generally accepted accounting
principles 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.
Reclassifications
In the December 31, 2006 consolidated balance sheet, we have reclassified a $2.2 million liability
that was previously netted against our accounts receivable affiliates balance to conform to our
2007 presentation. This liability is now presented as accounts payable affiliates.
Cash and Cash Equivalents
For purposes of the statements of cash flows, we consider all highly liquid investments with
maturity of three months or less at the time of purchase to be cash equivalents. The carrying
amounts reported on the balance sheet approximate fair value due to the short-term maturity of
these instruments.
Accounts Receivable
The majority of the accounts receivable are due from affiliates of Holly, Alon or independent
companies in the petroleum industry. Credit is extended based on evaluation of the customers
financial condition and, in certain circumstances, collateral such as letters of credit or
guarantees, may be required. Credit losses are charged to income when accounts are deemed
uncollectible and historically have been minimal.
Inventories
Inventories consisting of materials and supplies used for operations are stated at the lower of
cost, using the average cost method, or market and are shown under prepaid and other current
assets in our consolidated balance sheets.
Properties and Equipment
Properties and equipment are stated at cost. Depreciation is provided by the straight-line method
over the estimated useful lives of the assets; primarily 10 to 16 years for pipeline and terminal
facilities, 23 to 33 years for regulated pipelines and 3 to 10 years for corporate and other
assets. Maintenance, repairs and major replacements are generally expensed as incurred. Costs of
replacements constituting improvement are capitalized.
Transportation Agreements
The transportation agreement assets are stated at cost and are being amortized over the periods of
the agreements using the straight-line method.
Long-Lived Assets
We evaluate long-lived assets, including intangible assets, for potential impairment by identifying
whether indicators of impairment exist and, if so, assessing whether the long-lived assets are
recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss,
if any, to be recorded is equal to the amount by which a long-lived assets carrying value exceeds
its fair value. No impairments of long-lived assets were recorded during the periods included in
these financial statements.
Asset Retirement Obligations
We record legal obligations associated with the retirement of long-lived assets that result from
the acquisition, construction, development and/or the normal operation of our long-lived assets.
The fair value of the estimated cost to retire a tangible long-lived asset is recorded in the
period in which the
- 65 -
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,
2007, an asset retirement obligation of $0.3 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 recognize shortfall billings as revenue prior to the expiration of the contractual term period
to provide services only when we determine with a high likelihood that we will not be required to
provide services within the allowed period. We determine this when based on current and projected
shipping levels, that our pipeline systems will not have the necessary capacity to enable a
customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit
within its respective contractual shortfall make up period and the customer acknowledges that its
anticipated shipment levels will not permit it to utilize such a shortfall credit within the
respective contractual make up period. To date, we have not recognized any shortfall billings as
revenue prior to the expiration of the contractual term period.
Additional pipeline transportation revenues result from an operating lease to a third party of an
interest in the capacity of one of our pipelines.
Taxes billed and collected from our pipeline and terminal customers are recorded on a net basis
with no effect on net income.
Environmental Costs
Environmental costs are expensed if they relate to an existing condition caused by past operations
and do not contribute to current or future revenue generation. Liabilities are recorded when site
restoration and environmental remediation, cleanup and other obligations are either known or
considered probable and can be reasonably estimated. Environmental costs recoverable through
insurance, indemnification arrangements or other sources are included in other assets to the extent
such recoveries are considered probable.
State Income Tax
In May 2006, the State of Texas enacted a bill that replaced the existing franchise tax with a
margin tax. Effective January 1, 2007, the margin tax applies to legal entities conducting
business in Texas, including previously non-taxable entities such as limited partnerships and
limited liability partnerships. The margin tax is based on our Texas sourced taxable margin. The
tax is calculated by applying a tax rate to a base that considers both revenues and expenses and
therefore has the characteristics of an income tax. As a result, we recorded $0.3 million in state
income tax for the year ended December 31, 2007 that is solely attributable to the Texas margin
tax.
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.
- 66 -
Net income for financial statement purposes may differ significantly from taxable income reportable
to unitholders as a result of differences between the tax bases and financial reporting bases of
assets and liabilities and the taxable income allocation requirements under the partnership
agreement. Individual unitholders have different investment bases depending upon the timing and
price of acquisition of their partnership units. Furthermore, each unitholders tax accounting,
which is partially dependent upon the unitholders tax position, differs from the accounting
followed in the consolidated financial statements. Accordingly, the aggregate difference in the
basis of our net assets for financial and tax reporting purposes cannot be readily determined
because information regarding each unitholders tax attributes in our partnership is not available
to us.
Net Income per Limited Partners Unit
We have identified the general partner interest and the subordinated units as participating
securities and use the two-class method when calculating the net income per unit applicable to
limited partners, which is based on the weighted-average number of common and subordinated units
outstanding during the year. Net income per unit applicable to limited partners (including
subordinated units and Class B subordinated units) is computed by dividing limited partners
interest in net income, after deducting the general partners 2% interest and incentive
distributions, by the weighted-average number of outstanding common and subordinated units.
Recent Accounting Pronouncements
Interpretation No. 48 Accounting for Uncertainty in Income Taxes"
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes.
This interpretation clarifies the accounting for uncertainty in income taxes recognized in an
enterprises financial statements by prescribing a recognition threshold and measurement attribute
for the financial statement recognition and measurement of a tax position taken or expected to be
taken in a tax return. This interpretation also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods, disclosure and transition.
This interpretation is effective for fiscal years beginning after December 15, 2006. We adopted
this standard effective January 1, 2007. The adoption of this standard did not have a material
impact on our financial condition, results of operations and cash flows.
Statement of Financial Accounting Standards (SFAS) No. 157 Fair Value Measurements"
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This standard simplifies
and codifies guidance on fair value measurements under generally accepted accounting principles.
This standard defines fair value, establishes a framework for measuring fair value and prescribes
expanded disclosures about fair value measurements. This standard is effective for fiscal years
beginning after November 15, 2007. We do not anticipate that the adoption of this standard will
have a material effect on our financial condition, results of operations and cash flows.
SFAS No. 133 Implementation Issue No. E23 Issues Involving the Application of the Shortcut Method
under Paragraph 68"
In January 2008, the FASB posted SFAS No. 133 Implementation Issue No. E23, Issues Involving the
Application of the Shortcut Method under Paragraph 68. This standard addresses issues pertaining
to the application of the shortcut method in accounting for hedges when the settlement of a hedged
item occurs subsequent to the interest rate swap trade date. It also addresses hedging
relationships when the transaction price of an interest rate swap is zero. This standard is
effective for hedging relationships designated on or after January 1, 2008 and requires the
reassessment of preexisting hedges utilizing the shortcut method under this new guidance. While we
are currently evaluating this standard, we do not anticipate that the adoption of this standard
will have a material effect on our financial condition, results of operations and cash flows.
- 67 -
Note 2: Acquisitions
Alon Transaction
On February 28, 2005, we acquired from Alon four refined products pipelines, an associated tank
farm and two refined products terminals. These pipelines and terminals are located primarily in
Texas and transport and terminal light refined products for Alons refinery in Big Spring, Texas.
The total consideration paid for these pipeline and terminal assets was $120.0 million in cash and
937,500 of our Class B subordinated units which, subject to certain conditions, will convert into
an equal number of common units on February 28, 2010. We financed the Alon transaction with a
portion of the proceeds of our private offering of $150.0 million principal amount of 6.25% Senior
Notes due 2015 (see Note 6 for further information on the Senior Notes). In connection with the
Alon transaction, we entered into a 15-year pipelines and terminals agreement with Alon expiring
2020 (the Alon PTA). Under this agreement, Alon agreed to transport on our pipelines and
throughput in our terminals a volume of refined products that would result in minimum revenue
levels each year that will change annually based on changes in the PPI, but will not decrease below
the initial $20.2 million annual amount. Following the March 1, 2007 PPI rate adjustment, Alons
total minimum commitment for the twelve months ending February 29, 2008 is $20.9 million. The
agreed upon tariffs will increase or decrease each year at a rate equal to the percentage change in
the PPI, but not below the initial tariffs. Alons minimum volume commitment was calculated based
on 90% of Alons then recent usage of these pipelines and terminals taking into account an
expansion of Alons Big Spring, Texas refinery (Big Spring Refinery) completed in February 2005.
At revenue levels above 105% of the base revenue amount, as adjusted each year for changes in the
PPI, Alon will receive an annual 50% discount on incremental revenues. Alons obligations under
the Alon PTA may be reduced or suspended under certain circumstances. We granted Alon a second
mortgage on the pipelines and terminals acquired from Alon to secure certain of Alons rights under
the Alon PTA. Alon has a right of first refusal to purchase the pipelines and terminals if we
decide to sell them in the future. Additionally, we entered into an environmental agreement with
Alon with respect to pre-closing environmental costs and liabilities relating to the pipelines and
terminals acquired from Alon, under which Alon, for a ten year term expiring in 2015, will
indemnify us subject to a $100,000 deductible and a $20.0 million maximum liability cap.
The consideration for the Alon pipeline and terminal assets was allocated to the individual assets
acquired based on their estimated fair values. The aggregate consideration amounted to $146.7
million, which consisted of $24.7 million fair value of our Class B subordinated units, $120.0
million in cash and $2.0 million of transaction costs. In accounting for this acquisition, we
recorded pipeline and terminal assets of $86.7 million and an intangible asset of $60.0 million,
representing the allocated value of the 15-year Alon PTA. This intangible asset is included in
Transportation agreements, net in our consolidated balance sheets.
Holly Intermediate Pipelines Transaction
On July 8, 2005, we acquired pursuant to a definitive purchase agreement (the Purchase Agreement)
Hollys Intermediate Pipelines which connect its Lovington, New Mexico and Artesia, New Mexico
refining facilities. The total consideration was $81.5 million, which consisted of $77.7 million
in cash, 70,000 common units of HEP and a capital account credit of $1.0 million to maintain
Hollys existing general partner interest in the Partnership. We financed the cash portion of the
consideration for the Intermediate Pipelines with the proceeds raised from (a) the private sale of
1,100,000 of our common units for $45.1 million to a limited number of institutional investors
which closed simultaneously with the acquisition and (b) an additional $35.0 million in principal
amount of our 6.25% Senior Notes due 2015. This acquisition was made pursuant to an option to
purchase these pipelines granted by Holly to us at the time of our initial public offering in July
2004.
In connection with this transaction, we entered into a 15-year pipelines agreement with Holly (the
Holly IPA) which expires in 2020. Under this agreement, Holly agreed to transport volumes of
intermediate products on the Intermediate Pipelines that would result in initial minimum funds to
us of $11.8 million each year that will change annually based on changes in the PPI. Following the
July 1, 2007 PPI
- 68 -
adjustment, the volume commitments by Holly under the Holly IPA will result in minimum funds to us
of $12.8 million annually. The agreed upon tariff is adjusted each year at a rate equal to the
percentage change in the PPI, but the minimum commitment will not decrease as a result of a
decrease in the PPI. Hollys minimum revenue commitment applies only to the Intermediate
Pipelines, and Holly will not be able to spread its minimum revenue commitment among pipeline
assets HEP already owns or subsequently acquires. If Holly fails to meet its minimum revenue
commitment 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 may be applied as a
credit in the following four quarters after Hollys minimum obligations are met. The Holly IPA may
be extended by the mutual agreement of the parties.
If new laws or regulations are enacted that require us to make substantial and unanticipated
capital expenditures with regard to the Intermediate Pipelines, we have the right to amend the
tariff rates to recover our costs of complying with these new laws or regulations (including a
reasonable rate of return). Under certain circumstances, either party may temporarily suspend its
obligations under the Holly IPA. We granted Holly a second mortgage on the Intermediate Pipelines
to secure certain of Hollys rights under the Holly IPA. Holly has agreed to provide $2.5 million
of additional indemnification above the initial $15.0 million of indemnification under certain
provisions of an omnibus agreement that we entered with Holly in July 2004 (the Omnibus
Agreement) that previously provided for environmental noncompliance and remediation liabilities
occurring or existing before the closing date of the Purchase Agreement, bringing the total
indemnification provided to us from Holly to $17.5 million. Of this total, indemnification above
$15.0 million relates solely to the Intermediate Pipelines.
As this transaction was among entities under common control, we recorded the acquired assets at
Hollys historic book value of $6.8 million. The $71.9 million excess of the purchase price over
the historic book value is recorded as a reduction to partners equity for financial accounting
purposes.
Note 3: Properties and Equipment
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands) |
|
Pipelines and terminals |
|
$ |
196,800 |
|
|
$ |
195,688 |
|
Land and right of way |
|
|
22,825 |
|
|
|
22,486 |
|
Other |
|
|
5,706 |
|
|
|
5,267 |
|
Construction in progress |
|
|
9,103 |
|
|
|
1,539 |
|
|
|
|
|
|
|
|
|
|
|
234,434 |
|
|
|
224,980 |
|
Less accumulated depreciation |
|
|
75,834 |
|
|
|
64,496 |
|
|
|
|
|
|
|
|
|
|
$ |
158,600 |
|
|
$ |
160,484 |
|
|
|
|
|
|
|
|
During the years ended December 31, 2007 and 2006, we did not capitalize any interest related to
major construction projects.
Note 4: Transportation Agreements
Our transportation agreements consist of the following:
|
|
The Alon transportation agreement represents a portion of the total purchase price of the
Alon assets that was allocated based on an estimated fair value derived under the 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. |
- 69 -
|
|
The Rio Grande transportation agreement represented costs incurred by Rio Grande in
constructing certain pipeline and terminal facilities located in Mexico, which were then
contributed to an affiliate of Pemex, the national oil company of Mexico. In exchange, Rio
Grande received a 10-year transportation agreement from BP plc (BP). The initial 10-year
term of this agreement expired in April 2007. The agreement was extended for an additional
year and expires in April 2008. The carrying amount of this asset was fully amortized and
retired in April 2007. |
The carrying amounts of the transportation agreements are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands) |
|
Alon transportation agreement |
|
$ |
59,933 |
|
|
$ |
59,933 |
|
Rio Grande transportation agreement |
|
|
|
|
|
|
20,836 |
|
|
|
|
|
|
|
|
|
|
|
59,933 |
|
|
|
80,769 |
|
Less accumulated amortization |
|
|
5,660 |
|
|
|
23,948 |
|
|
|
|
|
|
|
|
|
|
$ |
54,273 |
|
|
$ |
56,821 |
|
|
|
|
|
|
|
|
Note 5: Employees, Retirement and Benefit Plans
Employees who provide direct services to us are employed by Holly Logistic Services, L.L.C. (HLS), a
Holly subsidiary. Their costs, including salaries, bonuses, payroll taxes, benefits, and other
direct costs, are charged to us monthly in accordance with the Omnibus Agreement.
These employees participate in the retirement and benefit plans of Holly. Our share of retirement
and benefit plan costs for the years ended December 31, 2007, 2006 and 2005 was $1.3 million, $1.4
million and $0.9 million, respectively. Included in these amounts are retirement costs of $0.6
million, $0.5 million and $0.4 million for the years ended December 31, 2007, 2006 and 2005,
respectively.
We have adopted a Long-Term Incentive Plan for employees, consultants and directors who perform
services for us. The Long-Term Incentive Plan consists of four components: restricted units,
performance units, unit options and unit appreciation rights.
On December 31, 2007, we had two types of equity-based compensation, which are described below.
The compensation cost charged against income for these plans was $1.3 million, $0.9 million and
$0.2 million for the years ended December 31, 2007, 2006 and 2005, respectively. It is currently
our policy to purchase units in the open market instead of issuing new units for settlement of
restricted unit grants. At December 31, 2007, 350,000 units were authorized to be granted under
the equity-based compensation plans, of which 260,115 had not yet been granted.
We elected early adoption of SFAS No. 123 (revised) on July 1, 2005, based on modified prospective
application. The effect of this change in accounting principle was immaterial to our financial
condition and results of operations.
Restricted Units
Under our Long-Term Incentive Plan, we grant restricted units to selected employees, consultants
and directors who perform services for us, with vesting generally over a period of one to five
years. Certain restricted units granted to our directors vest quarterly. Although full ownership
of the units does not transfer to the recipients until the units vest, the recipients have
distribution and voting rights on these units from the date of grant. The vesting for certain key
executives is contingent upon certain earnings per unit targets being realized. The fair value of
each unit of restricted unit awards was measured at the market price as of the date of grant and is
being amortized over the vesting period, including the units issued to the key executives, as we
expect those units to fully vest.
- 70 -
A summary of restricted unit activity and changes during the year ended December 31, 2007 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, 2007 (not vested) |
|
|
36,597 |
|
|
$ |
40.21 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
23,523 |
|
|
|
47.10 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(1,555 |
) |
|
|
44.17 |
|
|
|
|
|
|
|
|
|
Vesting and transfer of full ownership to recipients |
|
|
(13,854 |
) |
|
|
36.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007 (not vested) |
|
|
44,711 |
|
|
$ |
44.77 |
|
|
1.2 years |
|
$ |
1,956 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the year ended December 31, 2007, 13,854 restricted units having an intrinsic value of $0.6
million and a fair value of $0.5 million were vested and transferred to recipients of our
restricted unit grants. There were no restricted units vested or transferred to recipients during
the years ended December 31, 2006 and 2005. As of December 31, 2007, there was $0.7 million of
total unrecognized compensation costs related to nonvested restricted unit grants. That cost is
expected to be recognized over a weighted-average period of 1.2 years.
In 2007, we paid $1.1 million for the purchase of 23,523 of our common units in the open market for
the recipients of all 2007 restricted unit grants.
Performance Units
Under our Long-Term Incentive Plan, we grant performance units to selected executives and employees
who perform services for us. These performance units are payable upon meeting the performance
criteria over a service period, and generally vest over a period of three years. The amount
payable under the initial performance grant of 1,514 units in 2005 is based upon our unit price and
upon our total unitholder return during the requisite period as compared to the total unitholder
return of a selected peer group of partnerships. The amount payable under all other performance
unit grants is based upon the growth in distributions per limited partner unit during the requisite
period.
We granted 12,321 performance units to certain officers in February 2007. These units will vest
over a three-year performance period ending December 31, 2009, and are payable in HEP common units.
The number of units actually earned will be based on the growth of distributions to limited
partners over the performance period, and can range from 50% to 150% of the number of performance
units issued. The fair value of these performance units is based on the grant date closing unit
price of $46.12 and will apply to the number of units ultimately awarded.
A summary of performance unit activity and changes during the year ended December 31, 2007 is
presented below:
|
|
|
|
|
|
|
Payable |
Performance Units |
|
In Units |
Outstanding at January 1, 2007 (not vested) |
|
|
14,016 |
|
Vesting and payment of units to recipients |
|
|
|
|
Granted |
|
|
12,321 |
|
Forfeited |
|
|
(2,189 |
) |
|
|
|
|
|
Outstanding at December 31, 2007 (not vested) |
|
|
24,148 |
|
|
|
|
|
|
There were no payments or units issued for performance units vesting during the years ended
December 31, 2007, 2006 and 2005. Based on the weighted average fair value at December 31, 2007 of
$46.43, there was $0.7 million of total unrecognized compensation cost related to nonvested
performance units. That cost is expected to be recognized over a weighted-average period of 1.5
years.
- 71 -
Note 6: Debt
Credit Agreement
In August 2007, we entered into an amended and restated four-year, $100.0 million senior secured
revolving credit agreement expiring in August 2011 (the Credit Agreement) that amends and
restates our previous senior credit agreement in its entirety. Union Bank of California, N.A. is
one of the lenders and serves as administrative agent under this agreement. As of December 31,
2007 and December 31, 2006, we had no amounts outstanding under the Credit Agreement.
The Credit Agreement is available to fund capital expenditures, acquisitions, and working capital
and for general partnership purposes. Advances under the Credit Agreement that are designated for
working capital are short-term liabilities. Other advances under the Credit Agreement are
classified as long-term liabilities. In addition, the Credit Agreement is available to fund
letters of credit up to a $50.0 million sub-limit. Up to $20.0 million is available to fund
distributions to unitholders.
We have the right to request an increase in the maximum amount of the Credit Agreement, up to
$200.0 million. Such request will become effective if (a) certain conditions specified in the
Credit Agreement are met and (b) existing lenders under the Credit Agreement or other financial
institutions reasonably acceptable to the administrative agent commit to lend such increased
amounts under the agreement.
Our obligations under the Credit Agreement are secured by substantially all of our assets.
Indebtedness under the Credit Agreement is recourse to HEP Logistics Holdings, L.P., our general
partner, and guaranteed by our wholly-owned subsidiaries.
We may prepay all loans at any time without penalty, except for payment of certain breakage and
related costs. We are required to reduce all working capital borrowings under the Credit Agreement
to zero for a period of at least 15 consecutive days once each twelve-month period prior to the
maturity date of the agreement.
Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference
rate as announced by the administrative agent plus an applicable margin (ranging from 0.25% to
1.50%) or (b) at a rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable
margin (ranging from 1.00% to 2.50%). In each case, the applicable margin is based upon the ratio
of our funded debt (as defined in the agreement) to EBITDA (earnings before interest, taxes,
depreciation and amortization, as defined in the Credit Agreement). We incur a commitment fee on
the unused portion of the Credit Agreement at a rate ranging from 0.20% to 0.50% based upon the
ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters. At
December 31, 2007, we are subject to the 0.25% rate on the $100.0 million of the unused commitment
on the Credit Agreement. The agreement matures in August 2011. At that time, the agreement will
terminate and all outstanding amounts thereunder will be due and payable.
The Credit Agreement imposes certain requirements, including: a prohibition against distribution to
unitholders if, before or after the distribution, a potential default or an event of default as
defined in the agreement would occur; limitations on our ability to incur debt, make loans, acquire
other companies, change the nature of our business, enter a merger or consolidation, or sell
assets; and covenants that require maintenance of a specified EBITDA to interest expense ratio and
debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able
to accelerate the maturity of the debt and exercise other rights and remedies.
Senior Notes Due 2015
Our Senior Notes maturing March 1, 2015 are registered with the U.S. Securities and Exchange
Commission (SEC) and bear interest at 6.25% (Senior Notes). The Senior Notes are unsecured and
impose certain restrictive covenants, including limitations on our ability to incur additional
indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into
transactions with affiliates,
- 72 -
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.
The $185.0 million principal amount of Senior Notes is recorded at $181.4 million in our
consolidated balance sheets at December 31, 2007. The difference of $3.6 million is due to $2.7
million of unamortized discount and $0.9 million relating to the fair value of the interest rate
swap contract discussed below.
Interest Rate Risk Management
We have entered into an interest rate swap contract to effectively convert the interest expense
associated with $60.0 million of our 6.25% Senior Notes from a fixed rate to variable rates. The
interest rate on the $60.0 million notional amount is equal to three month LIBOR plus an applicable
margin of 1.1575%. The variable rate being paid on the notional amount at December 31, 2007 was
6.281%, including the applicable margin. The maturity of the swap contract is March 1, 2015,
matching the maturity of the Senior Notes.
This interest rate swap has been designated as a fair value hedge as defined by SFAS No. 133. Our
interest rate swap meets the conditions required to assume no ineffectiveness under SFAS No. 133
and, therefore, we have used the shortcut method of accounting prescribed for fair value hedges
by SFAS No. 133. Accordingly, we adjust the carrying value of the swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair
value is being hedged. We record interest expense equal to the variable rate payments under the
swap.
The fair value of our interest rate swap of $0.9 million and $1.2 million is included in Other
long-term liabilities in our consolidated balance sheets at December 31, 2007 and 2006,
respectively. The offsetting entry to adjust the carrying value of the debt securities whose fair
value is being hedged is recognized as a reduction of Long-term debt in our consolidated balance
sheets at December 31, 2007 and 2006.
Other Debt Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands) |
|
Interest on outstanding debt: |
|
|
|
|
|
|
|
|
|
|
|
|
Senior Notes, net of interest rate swap |
|
$ |
11,867 |
|
|
$ |
11,588 |
|
|
$ |
8,245 |
|
Credit Agreement |
|
|
|
|
|
|
|
|
|
|
164 |
|
Amortization of discount and deferred issuance costs |
|
|
1,008 |
|
|
|
968 |
|
|
|
785 |
|
Commitment fees |
|
|
414 |
|
|
|
500 |
|
|
|
439 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense |
|
$ |
13,289 |
|
|
$ |
13,056 |
|
|
$ |
9,633 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest (1) |
|
$ |
12,316 |
|
|
$ |
11,912 |
|
|
$ |
6,793 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net of cash received under our interest rate swap agreement of $3.8 million,
$3.8 million and $1.7 million for the years ended December 31, 2007, 2006 and 2005,
respectively. |
The estimated fair value of our Senior Notes was $169.3 million at December 31, 2007.
Note 7: Commitments and Contingencies
We lease certain facilities, pipelines and rights of way under operating leases, most of which
contain renewal options. In 2007, we exercised the first of three 10-year lease extensions under
our lease agreement for the refined products pipeline between White Lakes Junction and Kutz Station
in New Mexico. The right of way agreements have various termination dates through 2053.
- 73 -
As of December 31, 2007, 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 |
|
2008 |
|
$ |
6,352 |
|
2009 |
|
|
5,973 |
|
2010 |
|
|
5,899 |
|
2011 |
|
|
5,902 |
|
2012 |
|
|
5,891 |
|
Thereafter |
|
|
27,254 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
57,271 |
|
|
|
|
|
Rental expense charged to operations was $6.1 million, $5.9 million and $5.6 million for the years
ended December 31, 2007, 2006 and 2005, respectively.
We are a party to various legal and regulatory proceedings, none of which we believe will have a
material adverse impact on our financial condition, results of operations or cash flows.
Note 8: Significant Customers
All revenues are domestic revenues, of which over 90% are currently generated from our three
largest customers: Holly, Alon and BP. The major concentration of our petroleum products pipeline
systems revenues is derived from activities conducted in the southwest United States. The
following table presents the percentage of total revenues generated by each of these three
customers:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2007 |
|
2006 |
|
2005 |
Holly |
|
|
60 |
% |
|
|
59 |
% |
|
|
55 |
% |
Alon |
|
|
27 |
% |
|
|
28 |
% |
|
|
30 |
% |
BP |
|
|
9 |
% |
|
|
9 |
% |
|
|
11 |
% |
Note 9: Related Party Transactions
Holly
We serve Hollys refineries in New Mexico and Utah under two 15-year pipeline and terminal
agreements. One of these agreements relates to the pipelines and terminals contributed by Holly to
us at the time of our initial public offering and expires in 2019 (Holly PTA). The Holly IPA
relates to the Intermediate Pipelines acquired from Holly in July 2005 and expires in 2020. The
substantial majority of our business is devoted to providing transportation and terminalling
services to Holly. The minimum revenue commitments under the Holly PTA and the Holly IPA increase
each year at a rate equal to the percentage change in the producer price index (PPI), but will
not decrease as a result of a decrease in the PPI.
Following the July 1, 2007 PPI rate adjustment, the volume commitment by Holly under the Holly PTA
will produce at least $39.6 million of revenue for the twelve months ending June 30, 2008. Under
the Holly IPA, Holly agreed to transport volumes of intermediate products on the Intermediate
Pipelines that following the July 1, 2007 PPI rate adjustment, will result in minimum funds to us
of $12.8 million for the twelve months ending June 30, 2008.
If Holly fails to meet its minimum volume commitments in any quarter, it is 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 may be applied as a credit in the following four quarters after Hollys minimum
obligations are met.
- 74 -
In October 2007, we entered into an agreement with Holly that amends the Holly PTA under which we
have agreed to expand our refined products pipeline system between Artesia, New Mexico and El Paso,
Texas (the South System). The expansion of the South System will include replacing 85 miles of
8-inch pipe with 12-inch pipe, adding 150,000 barrels of refined product storage at our El Paso
Terminal, improving existing pumps, adding a tie-in to the Kinder Morgan pipeline to Tucson and
Phoenix, Arizona, and making related modifications. The cost of this project is estimated to be
$48.3 million. Currently, we are expecting to complete this project by January 2009. The agreement
also provides for a tariff increase, expected to be effective May 1, 2008, on Holly shipments on
our refined product pipelines.
Under certain provisions of the Omnibus Agreement that we entered with Holly in July 2004 and
expires in 2019, we pay Holly an annual administrative fee, initially $2.0 million for each of the
three years following the closing of our initial public offering, for the provision by Holly or its
affiliates of various general and administrative services to us. Effective July 1, 2007, the
annual fee increased to $2.1 million in accordance with provisions under the agreement. 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 consideration for Hollys assistance in obtaining our joint venture opportunity in a new 95-mile
intrastate pipeline system (the SLC Pipeline) now under construction by Plains All American
Pipeline, L.P. (Plains), we will pay Holly a $2.5 million finders fee upon the closing of our
investment in the joint venture with Plains. See Note 13 for further information on this proposed
joint venture.
|
|
Pipeline and terminal revenues received from Holly were $61.0 million, $52.9 million and
$44.2 million for the years ended December 31, 2007, 2006 and 2005, respectively. These
amounts include the revenues received under the Holly PTA and Holly IPA. |
|
|
Other revenues for the year ended December 31, 2007 were $2.7 million related to our sale
of inventory of accumulated terminal overages of refined product. These overages arose from
net product gains at our terminals from the beginning of 2005 through the third quarter of
2007. We have negotiated an amendment to our pipelines and terminals agreement with Holly
that provides that such terminal overages of refined product shall belong to Holly in the
future. |
|
|
Holly charged general and administrative services under the Omnibus Agreement of $2.0
million for each of the years ended December 31, 2007, 2006 and 2005. |
|
|
We reimbursed Holly for costs of employees supporting our operations of $8.5 million, $7.7
million and $6.5 million for the years ended December 31, 2007, 2006 and 2005, respectively. |
|
|
Holly reimbursed us $0.3 million for the year ended December 31, 2007 and $0.2 million for
each of the years ended December 31, 2006 and 2005 for certain costs paid on their behalf. |
|
|
We distributed $22.8 million, $20.3 million and $16.5 million for the years ended December
31, 2007, 2006 and 2005, respectively, to Holly as regular distributions on its subordinated
units, common units and general partner interest. |
|
|
We acquired the Intermediate Pipelines from Holly in July 2005, which resulted in payment
to Holly of a purchase price of $71.9 million in excess of the basis of the assets received.
See Note 2 for further information on the Intermediate Pipelines transaction. |
|
|
Our accounts receivable from Holly was $5.7 million at December 31, 2007 and 2006. |
|
|
Our accounts payable to Holly were $6.0 million and $2.2 million at December 31, 2007 and
2006, respectively. |
- 75 -
|
|
Holly failed to meet its minimum volume commitment for each of the first nine quarters of
the Holly IPA. Through December 31, 2007, we have charged Holly $4.5 million for these
shortfalls of which zero and $0.2 million is included in affiliate accounts receivable at
December 31, 2007 and 2006 respectively. |
|
|
Our revenues for the years ended December 31, 2007 and 2006 included shortfalls billed
under the Holly IPA of $2.4 million in 2006 and $1.0 million in 2005, respectively, as Holly
did not exceed its minimum volume commitment in any of the subsequent four quarters in 2007
and 2006. Deferred revenue in the consolidated balance sheets at December 31, 2007 and 2006,
includes $1.1 million and $2.4 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 $1.1 million deferred at December 31, 2007. |
BP
We have a 70% ownership interest in Rio Grande and BP owns the other 30%. Due to the ownership
interest and resulting consolidation, BP is a related party to us.
|
|
BP is the sole customer of Rio Grande. BPs agreement to ship on the Rio Grande pipeline
expires in April 2008. We recorded revenues from them of $9.2 million, $8.4 million and $8.8
million for the years ended December 31, 2007, 2006 and 2005, respectively. |
|
|
Rio Grande paid distributions to BP of $1.3 million, $1.5 million and $2.2 million for the
years ended December 31, 2007, 2006 and 2005, respectively. |
|
|
Included in our accounts receivable trade at December 31, 2007 and 2006 were $1.5
million and $2.1 million, respectively, which represented the receivable balance of Rio Grande
from BP. |
Alon
We have a 15-year pipelines and terminals agreement with Alon, expiring in 2020, under which Alon
has agreed to transport on our pipelines and throughput through our terminals volumes of refined
products that results in a minimum level of annual revenue. The agreed upon tariffs are increased
or decreased annually at a rate equal to the percentage change in PPI, but not below the initial
tariff rate. Following the March 1, 2007 PPI rate adjustment, Alons total minimum commitment for
the twelve months ending February 29, 2008 is $20.9 million.
Alon became a related party when it acquired all of our Class B subordinated units in connection
with our acquisition of assets from them on February 28, 2005.
|
|
We recognized $21.8 million, $18.0 million and $17.6 million of revenues for pipeline
transportation and terminalling services under the Alon PTA and $7.1 million, $6.9 million and
$5.6 million under a pipeline capacity lease for the years ended December 31, 2007, 2006 and
2005, respectively. The pipeline lease agreement with Alon was amended effective August 31,
2007 to extend two capacity leases for 10 years to August 31, 2018 and July 31, 2020,
respectively, to reduce the total leased capacity from 20,000 to 17,500 barrels per day
(bpd) effective September 1, 2008, and to allow Alon an option, effective from September 1,
2008, to increase the leased capacity by 2,500 bpd for a term of 10 years. |
|
|
We paid $2.6 million, $2.4 million and $1.6 million to Alon for distributions on our Class
B subordinated units for the years ended December 31, 2007, 2006 and 2005, respectively. |
|
|
Included in our accounts receivable trade at December 31, 2007 and 2006 were $3.5
million and $5.0 million, respectively, which represented our receivable balance from Alon. |
- 76 -
|
|
Our revenues for the year ended December 31, 2007 included $3.1 million of shortfalls
billed under the Alon PTA in 2006 as Alon did not exceed its minimum revenue obligation in any
of the subsequent four quarters. Deferred revenue in the consolidated balance sheets at
December 31, 2007 and 2006 includes $2.6 million and $3.1 million, respectively, relating to
the Alon PTA. It is possible that Alon may not exceed its minimum obligations under the Alon
PTA to allow Alon to receive credit for any of the $2.6 million deferred at December 31, 2007. |
Note 10: Partners Equity, Allocations and Cash Distributions
Issuances of units
Upon the closing of our initial public offering on July 13, 2004, Holly received 7,000,000
subordinated units, which constituted 49% ownership of us at that time, and a 2% general partner
interest. During the subordination period, the common units have the right to receive
distributions of available cash from operating surplus in an amount equal to the minimum quarterly
distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly
distribution on the common units from prior quarters, before any distributions of available cash
from operating surplus may be made on the subordinated units. The purpose of the subordinated
units is to increase the likelihood that during the subordination period there will be available
cash to be distributed on the common units. The subordination period will extend until the first
day of any quarter beginning after June 30, 2009 that each of the following tests are met:
distributions of available cash from operating surplus on each of the outstanding common units and
subordinated units equaled or exceeded the minimum quarterly distribution for each of the three
consecutive, non-overlapping four-quarter periods immediately preceding that date; the adjusted
operating surplus (as defined in its partnership agreement) generated during each of the three
consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or
exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and
subordinated units during those periods on a fully diluted basis and the related distribution on
the 2% general partner interest during those periods; and there are no arrearages in payment of the
minimum quarterly distribution on the common units. If the unitholders remove the general partner
without cause, the subordination period may end before June 30, 2009.
The Holly subordinated units may convert to common units on a one-for-one basis when certain
conditions are met. The partnership agreement sets forth the calculation to be used to determine
the amount and priority of cash distributions that the common unitholders, subordinated unitholders
and general partner will receive.
As partial consideration in the Alon transaction in the first quarter of 2005, we issued 937,500 of
our Class B subordinated units at a fair value of $24.7 million. Additionally, our general partner
contributed $0.6 million as an additional capital contribution to maintain its 2% general partner
interest.
We financed a portion of the cash consideration paid for the Intermediate Pipelines with $45.1
million of proceeds raised from the private sale of 1,100,000 of our common units to a limited
number of institutional investors which closed on July 8, 2005. On September 2, 2005, we filed a
registration statement with the SEC using a shelf registration process which allows the
institutional investors to freely transfer their units. Additionally under this shelf process, we
may offer from time to time up to $800.0 million of our securities, through one or more prospectus
supplements that would describe, among other things, the specific amounts, prices and terms of any
securities offered and how the proceeds would be used. Any proceeds from the sale of securities
would be used for general business purposes, which may include, among other things, funding
acquisitions of assets or businesses, working capital, capital expenditures, investments in
subsidiaries, the retirement of existing debt and/or the repurchase of common units or other
securities.
In connection with the Intermediate Pipelines transaction, we issued 70,000 common units to Holly.
We also received a portion of the Intermediate Pipeline assets with $1.0 million book value as a
capital contribution from HEP Logistics Holdings, L.P. in order to maintain their 2% general
partner interest. As a result of these transactions, Hollys total ownership interest was reduced
from 51% at the time of our initial public offering to 45% in July 2005 following the Intermediate
Pipelines transaction.
- 77 -
Allocations of Net Income
Net income is allocated between limited partners and the general partner interest in accordance
with the provisions of the partnership agreement. Net income allocated to the general partner
includes any incentive distributions declared in the period. After the amount of incentive
distributions is allocated to the general partner, the remaining net income for the period is
generally allocated to the partners based on their weighted average ownership percentage during the
period.
Cash Distributions
We consider regular cash distributions to unitholders on a quarterly basis, although there is no
assurance as to the future cash distributions since they are dependent upon future earnings, cash
flows, capital requirements, financial condition and other factors. Our Credit Agreement prohibits
us from making cash distributions if any potential default or event of default, as defined in the
Credit Agreement, occurs or would result from the cash distribution.
Within 45 days after the end of each quarter, we distribute all of our available cash (as defined
in our partnership agreement) to unitholders of record on the applicable record date. The amount
of available cash generally is all cash on hand at the end of the quarter; less the amount of cash
reserves established by our general partner to provide for the proper conduct of our business,
comply with applicable law, any of our debt instruments, or other agreements; or provide funds for
distributions to our unitholders and to our general partner for any one or more of the next four
quarters; plus all cash on hand on the date of determination of available cash for the quarter
resulting from working capital borrowings made after the end of the quarter. Working capital
borrowings are generally borrowings that are made under our revolving Credit Agreement and in all
cases are used solely for working capital purposes or to pay distributions to partners.
We make distributions of available cash from operating surplus for any quarter during any
subordination period in the following manner: firstly, 98% to the common unitholders, pro rata, and
2% to the general partner, until we distribute for each outstanding common unit an amount equal to
the minimum quarterly distribution for that quarter; secondly, 98% to the common unitholders, pro
rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount
equal to any arrearages in payment of the minimum quarterly distribution on the common units for
any prior quarters during the subordination period; thirdly, 98% to the subordinated unitholders,
pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount
equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the
minimum quarterly distributions is distributed to the unitholders and the general partner based on
the percentages below.
The general partner, HEP Logistics Holdings, L.P., is entitled to incentive distributions if the
amount we distribute with respect to any quarter exceeds specified target levels shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage Interest in |
|
|
Total Quarterly Distribution |
|
Distributions |
|
|
Target Amount |
|
Unitholders |
|
General Partner |
Minimum Quarterly Distribution |
|
$0.50 |
|
|
98 |
% |
|
|
2 |
% |
First Target Distribution |
|
Up to $0.55 |
|
|
98 |
% |
|
|
2 |
% |
Second Target Distribution |
|
above $0.55 up to $0.625 |
|
|
85 |
% |
|
|
15 |
% |
Third Target distribution |
|
above $0.625 up to $0.75 |
|
|
75 |
% |
|
|
25 |
% |
Thereafter |
|
Above $0.75 |
|
|
50 |
% |
|
|
50 |
% |
- 78 -
The following table presents the allocation of our regular quarterly cash distributions to the
general and limited partners for each period in which declared.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(in thousands, except per unit data) |
|
General partner interest |
|
$ |
915 |
|
|
$ |
850 |
|
|
$ |
697 |
|
General partner incentive distribution |
|
|
2,191 |
|
|
|
1,182 |
|
|
|
188 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general partner distribution |
|
|
3,106 |
|
|
|
2,032 |
|
|
|
885 |
|
Limited partner distribution |
|
|
44,868 |
|
|
|
41,638 |
|
|
|
34,137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total regular quarterly cash distribution |
|
$ |
47,974 |
|
|
$ |
43,670 |
|
|
$ |
35,022 |
|
|
|
|
|
|
|
|
|
|
|
Cash distribution per unit applicable to
limited partners |
|
$ |
2.785 |
|
|
$ |
2.585 |
|
|
$ |
2.225 |
|
|
|
|
|
|
|
|
|
|
|
On January 29, 2008, we announced a cash distribution for the fourth quarter of 2007 of $0.725 per
unit. The distribution is payable on all common, subordinated, and general partner units and was
paid February 14, 2008 to all unitholders of record on February 7, 2008. The aggregate amount of
the distribution was $12.6 million, including $0.7 million paid to the general partner as an
incentive distribution.
As a master limited partnership, we distribute our available cash, which exceeds 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.
Note 11: Quarterly Financial Data (Unaudited)
Summarized quarterly financial data is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
Total |
|
|
|
|
|
|
(In thousands, except per unit data) |
|
|
|
|
Year ended December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
23,872 |
|
|
$ |
27,131 |
|
|
$ |
27,213 |
|
|
$ |
27,191 |
|
|
$ |
105,407 |
|
Operating income |
|
$ |
10,796 |
|
|
$ |
14,450 |
|
|
$ |
14,274 |
|
|
$ |
13,551 |
|
|
$ |
53,071 |
|
Net income |
|
$ |
7,434 |
|
|
$ |
11,006 |
|
|
$ |
10,690 |
|
|
$ |
10,141 |
|
|
$ |
39,271 |
|
Limited partners interest in net income |
|
$ |
6,854 |
|
|
$ |
10,280 |
|
|
$ |
9,896 |
|
|
$ |
9,309 |
|
|
$ |
36,339 |
|
Net income per limited partner unit basic
and diluted |
|
$ |
0.43 |
|
|
$ |
0.64 |
|
|
$ |
0.61 |
|
|
$ |
0.58 |
|
|
$ |
2.26 |
|
Distributions declared per limited partner unit |
|
$ |
0.675 |
|
|
$ |
0.690 |
|
|
$ |
0.705 |
|
|
$ |
0.715 |
|
|
$ |
2.785 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
22,438 |
|
|
$ |
18,527 |
|
|
$ |
22,899 |
|
|
$ |
25,330 |
|
|
$ |
89,194 |
|
Operating income |
|
$ |
10,312 |
|
|
$ |
6,028 |
|
|
$ |
10,801 |
|
|
$ |
13,239 |
|
|
$ |
40,380 |
|
Net income |
|
$ |
7,135 |
|
|
$ |
2,998 |
|
|
$ |
7,751 |
|
|
$ |
9,659 |
|
|
$ |
27,543 |
|
Limited partners interest in net income |
|
$ |
6,808 |
|
|
$ |
2,679 |
|
|
$ |
7,263 |
|
|
$ |
9,083 |
|
|
$ |
25,833 |
|
Net income per limited partner unit basic
and diluted |
|
$ |
0.42 |
|
|
$ |
0.17 |
|
|
$ |
0.45 |
|
|
$ |
0.56 |
|
|
$ |
1.60 |
|
Distributions declared per limited partner unit |
|
$ |
0.625 |
|
|
$ |
0.640 |
|
|
$ |
0.655 |
|
|
$ |
0.665 |
|
|
$ |
2.585 |
|
- 79 -
Note 12: Supplemental Guarantor/Non-Guarantor Financial Information
Obligations of Holly Energy Partners, L.P. (Parent) under the Senior Notes have been jointly and
severally guaranteed by each of its direct and indirect wholly-owned subsidiaries (Guarantor
Subsidiaries). These guarantees are full and unconditional. Rio Grande (Non-Guarantor), in
which we have a 70% ownership interest, is the only subsidiary which has not guaranteed these
obligations.
The following financial information presents condensed consolidating balance sheets, statements of
income, and statements of cash flows of the Parent, the Guarantor Subsidiaries and the
Non-Guarantor. The information has been presented as if the Parent accounted for its ownership in
the Guarantor Subsidiaries, and the Guarantor Subsidiaries accounted for the ownership of the
Non-Guarantor, using the equity method of accounting.
- 80 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Balance Sheet |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
December 31, 2007 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
Consolidated |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
2 |
|
|
$ |
8,060 |
|
|
$ |
2,259 |
|
|
$ |
|
|
|
$ |
10,321 |
|
Accounts receivable |
|
|
|
|
|
|
10,820 |
|
|
|
1,491 |
|
|
|
|
|
|
|
12,311 |
|
Intercompany accounts receivable (payable) |
|
|
(141,175 |
) |
|
|
141,553 |
|
|
|
(378 |
) |
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
183 |
|
|
|
363 |
|
|
|
|
|
|
|
|
|
|
|
546 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
(140,990 |
) |
|
|
160,796 |
|
|
|
3,372 |
|
|
|
|
|
|
|
23,178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties and equipment, net |
|
|
|
|
|
|
125,383 |
|
|
|
33,217 |
|
|
|
|
|
|
|
158,600 |
|
Investment in subsidiaries |
|
|
353,235 |
|
|
|
25,059 |
|
|
|
|
|
|
|
(378,294 |
) |
|
|
|
|
Transportation agreements, net |
|
|
|
|
|
|
54,273 |
|
|
|
|
|
|
|
|
|
|
|
54,273 |
|
Other assets |
|
|
1,302 |
|
|
|
1,551 |
|
|
|
|
|
|
|
|
|
|
|
2,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
213,547 |
|
|
$ |
367,062 |
|
|
$ |
36,589 |
|
|
$ |
(378,294 |
) |
|
$ |
238,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
|
|
|
$ |
8,499 |
|
|
$ |
533 |
|
|
$ |
|
|
|
$ |
9,032 |
|
Accrued interest |
|
|
(2,932 |
) |
|
|
5,928 |
|
|
|
|
|
|
|
|
|
|
|
2,996 |
|
Deferred revenue |
|
|
|
|
|
|
3,700 |
|
|
|
|
|
|
|
|
|
|
|
3,700 |
|
Accrued property taxes |
|
|
|
|
|
|
1,021 |
|
|
|
156 |
|
|
|
|
|
|
|
1,177 |
|
Other current liabilities |
|
|
6,387 |
|
|
|
(5,661 |
) |
|
|
101 |
|
|
|
|
|
|
|
827 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
3,455 |
|
|
|
13,487 |
|
|
|
790 |
|
|
|
|
|
|
|
17,732 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
181,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
181,435 |
|
Other long-term liabilities |
|
|
841 |
|
|
|
340 |
|
|
|
|
|
|
|
|
|
|
|
1,181 |
|
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,740 |
|
|
|
10,740 |
|
Partners equity |
|
|
27,816 |
|
|
|
353,235 |
|
|
|
35,799 |
|
|
|
(389,034 |
) |
|
|
27,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity |
|
$ |
213,547 |
|
|
$ |
367,062 |
|
|
$ |
36,589 |
|
|
$ |
(378,294 |
) |
|
$ |
238,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Balance Sheet |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
|
December 31, 2006 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
Consolidated |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
2 |
|
|
$ |
9,819 |
|
|
$ |
1,734 |
|
|
$ |
|
|
|
$ |
11,555 |
|
Accounts receivable |
|
|
|
|
|
|
10,970 |
|
|
|
2,085 |
|
|
|
|
|
|
|
13,055 |
|
Intercompany accounts receivable (payable) |
|
|
(78,952 |
) |
|
|
79,144 |
|
|
|
(192 |
) |
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
203 |
|
|
|
1,009 |
|
|
|
|
|
|
|
|
|
|
|
1,212 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
(78,747 |
) |
|
|
100,942 |
|
|
|
3,627 |
|
|
|
|
|
|
|
25,822 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties and equipment, net |
|
|
|
|
|
|
127,357 |
|
|
|
33,127 |
|
|
|
|
|
|
|
160,484 |
|
Investment in subsidiaries |
|
|
298,872 |
|
|
|
25,581 |
|
|
|
|
|
|
|
(324,453 |
) |
|
|
|
|
Transportation agreements, net |
|
|
|
|
|
|
56,271 |
|
|
|
550 |
|
|
|
|
|
|
|
56,821 |
|
Other assets |
|
|
1,453 |
|
|
|
1,191 |
|
|
|
|
|
|
|
|
|
|
|
2,644 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
221,578 |
|
|
$ |
311,342 |
|
|
$ |
37,304 |
|
|
$ |
(324,453 |
) |
|
$ |
245,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
|
|
|
$ |
5,554 |
|
|
$ |
425 |
|
|
$ |
|
|
|
$ |
5,979 |
|
Accrued interest |
|
|
2,941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,941 |
|
Deferred revenue |
|
|
|
|
|
|
5,486 |
|
|
|
|
|
|
|
|
|
|
|
5,486 |
|
Accrued property taxes |
|
|
|
|
|
|
726 |
|
|
|
142 |
|
|
|
|
|
|
|
868 |
|
Other current liabilities |
|
|
516 |
|
|
|
389 |
|
|
|
193 |
|
|
|
|
|
|
|
1,098 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
3,457 |
|
|
|
12,155 |
|
|
|
760 |
|
|
|
|
|
|
|
16,372 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
180,660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
180,660 |
|
Other long-term liabilities |
|
|
1,235 |
|
|
|
315 |
|
|
|
|
|
|
|
|
|
|
|
1,550 |
|
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,963 |
|
|
|
10,963 |
|
Partners equity |
|
|
36,226 |
|
|
|
298,872 |
|
|
|
36,544 |
|
|
|
(335,416 |
) |
|
|
36,226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity |
|
$ |
221,578 |
|
|
$ |
311,342 |
|
|
$ |
37,304 |
|
|
$ |
(324,453 |
) |
|
$ |
245,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 81 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year ended December 31, 2007 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
|
|
|
$ |
60,961 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
60,961 |
|
Third parties |
|
|
|
|
|
|
33,720 |
|
|
|
9,217 |
|
|
|
(1,239 |
) |
|
|
41,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94,681 |
|
|
|
9,217 |
|
|
|
(1,239 |
) |
|
|
102,659 |
|
Affiliates other |
|
|
|
|
|
|
2,748 |
|
|
|
|
|
|
|
|
|
|
|
2,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
97,429 |
|
|
|
9,217 |
|
|
|
(1,239 |
) |
|
|
105,407 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
|
|
|
|
30,523 |
|
|
|
3,627 |
|
|
|
(1,239 |
) |
|
|
32,911 |
|
Depreciation and amortization |
|
|
|
|
|
|
12,520 |
|
|
|
1,862 |
|
|
|
|
|
|
|
14,382 |
|
General and administrative |
|
|
2,730 |
|
|
|
2,135 |
|
|
|
178 |
|
|
|
|
|
|
|
5,043 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,730 |
|
|
|
45,178 |
|
|
|
5,667 |
|
|
|
(1,239 |
) |
|
|
52,336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(2,730 |
) |
|
|
52,251 |
|
|
|
3,550 |
|
|
|
|
|
|
|
53,071 |
|
Equity in earnings of subsidiaries |
|
|
54,362 |
|
|
|
2,487 |
|
|
|
|
|
|
|
(56,849 |
) |
|
|
|
|
Interest income (expense) |
|
|
(12,361 |
) |
|
|
(474 |
) |
|
|
79 |
|
|
|
|
|
|
|
(12,756 |
) |
Gain on sale of assets |
|
|
|
|
|
|
298 |
|
|
|
|
|
|
|
|
|
|
|
298 |
|
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,067 |
) |
|
|
(1,067 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,001 |
|
|
|
2,311 |
|
|
|
79 |
|
|
|
(57,916 |
) |
|
|
(13,525 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
39,271 |
|
|
|
54,562 |
|
|
|
3,629 |
|
|
|
(57,916 |
) |
|
|
39,546 |
|
State income tax |
|
|
|
|
|
|
(200 |
) |
|
|
(75 |
) |
|
|
|
|
|
|
(275 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
39,271 |
|
|
$ |
54,362 |
|
|
$ |
3,554 |
|
|
$ |
(57,916 |
) |
|
$ |
39,271 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year ended December 31, 2006 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
|
|
|
$ |
52,878 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
52,878 |
|
Third parties |
|
|
|
|
|
|
29,119 |
|
|
|
8,400 |
|
|
|
(1,203 |
) |
|
|
36,316 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81,997 |
|
|
|
8,400 |
|
|
|
(1,203 |
) |
|
|
89,194 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
|
|
|
|
27,009 |
|
|
|
2,824 |
|
|
|
(1,203 |
) |
|
|
28,630 |
|
Depreciation and amortization |
|
|
|
|
|
|
11,933 |
|
|
|
3,397 |
|
|
|
|
|
|
|
15,330 |
|
General and administrative |
|
|
2,794 |
|
|
|
2,055 |
|
|
|
5 |
|
|
|
|
|
|
|
4,854 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,794 |
|
|
|
40,997 |
|
|
|
6,226 |
|
|
|
(1,203 |
) |
|
|
48,814 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(2,794 |
) |
|
|
41,000 |
|
|
|
2,174 |
|
|
|
|
|
|
|
40,380 |
|
Equity in earnings of subsidiaries |
|
|
42,456 |
|
|
|
1,588 |
|
|
|
|
|
|
|
(44,044 |
) |
|
|
|
|
Interest income (expense) |
|
|
(12,119 |
) |
|
|
(132 |
) |
|
|
94 |
|
|
|
|
|
|
|
(12,157 |
) |
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(680 |
) |
|
|
(680 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
27,543 |
|
|
$ |
42,456 |
|
|
$ |
2,268 |
|
|
$ |
(44,724 |
) |
|
$ |
27,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 82 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year ended December 31, 2005 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
$ |
|
|
|
$ |
44,184 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
44,184 |
|
Third parties |
|
|
|
|
|
|
28,000 |
|
|
|
8,770 |
|
|
|
(834 |
) |
|
|
35,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72,184 |
|
|
|
8,770 |
|
|
|
(834 |
) |
|
|
80,120 |
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
|
|
|
|
|
23,270 |
|
|
|
2,896 |
|
|
|
(834 |
) |
|
|
25,332 |
|
Depreciation and amortization |
|
|
|
|
|
|
10,824 |
|
|
|
3,377 |
|
|
|
|
|
|
|
14,201 |
|
General and administrative |
|
|
1,966 |
|
|
|
2,064 |
|
|
|
17 |
|
|
|
|
|
|
|
4,047 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,966 |
|
|
|
36,158 |
|
|
|
6,290 |
|
|
|
(834 |
) |
|
|
43,580 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(1,966 |
) |
|
|
36,026 |
|
|
|
2,480 |
|
|
|
|
|
|
|
36,540 |
|
Equity in earnings of subsidiaries |
|
|
37,410 |
|
|
|
1,728 |
|
|
|
|
|
|
|
(39,138 |
) |
|
|
|
|
Interest expense |
|
|
(8,628 |
) |
|
|
(344 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
(8,984 |
) |
Minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(740 |
) |
|
|
(740 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
26,816 |
|
|
$ |
37,410 |
|
|
$ |
2,468 |
|
|
$ |
(39,878 |
) |
|
$ |
26,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Cash Flows |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year Ended December 31, 2007 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Cash flows from operating activities |
|
$ |
49,056 |
|
|
$ |
6,784 |
|
|
$ |
6,226 |
|
|
$ |
(3,010 |
) |
|
$ |
59,056 |
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to properties and equipment |
|
|
|
|
|
|
(8,556 |
) |
|
|
(1,401 |
) |
|
|
|
|
|
|
(9,957 |
) |
Proceeds from sale of assets |
|
|
|
|
|
|
325 |
|
|
|
|
|
|
|
|
|
|
|
325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,231 |
) |
|
|
(1,401 |
) |
|
|
|
|
|
|
(9,632 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to partners |
|
|
(47,974 |
) |
|
|
|
|
|
|
(4,300 |
) |
|
|
4,300 |
|
|
|
(47,974 |
) |
Cash distributions to minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,290 |
) |
|
|
(1,290 |
) |
Purchase of units for restricted unit grants |
|
|
(1,082 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,082 |
) |
Deferred financing costs |
|
|
|
|
|
|
(296 |
) |
|
|
|
|
|
|
|
|
|
|
(296 |
) |
Other |
|
|
|
|
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(49,056 |
) |
|
|
(312 |
) |
|
|
(4,300 |
) |
|
|
3,010 |
|
|
|
(50,658 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) for the year |
|
|
|
|
|
|
(1,759 |
) |
|
|
525 |
|
|
|
|
|
|
|
(1,234 |
) |
Beginning of year |
|
|
2 |
|
|
|
9,819 |
|
|
|
1,734 |
|
|
|
|
|
|
|
11,555 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
2 |
|
|
$ |
8,060 |
|
|
$ |
2,259 |
|
|
$ |
|
|
|
$ |
10,321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Cash Flows |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year Ended December 31, 2006 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Cash flows from operating activities |
|
$ |
44,304 |
|
|
$ |
930 |
|
|
$ |
4,049 |
|
|
$ |
(3,430 |
) |
|
$ |
45,853 |
|
Cash flows from investing activities additions to
properties and equipment |
|
|
|
|
|
|
(8,881 |
) |
|
|
(226 |
) |
|
|
|
|
|
|
(9,107 |
) |
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to partners |
|
|
(43,670 |
) |
|
|
|
|
|
|
(4,900 |
) |
|
|
4,900 |
|
|
|
(43,670 |
) |
Cash distributions to minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,470 |
) |
|
|
(1,470 |
) |
Purchase of units for restricted unit grants |
|
|
(634 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(634 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44,304 |
) |
|
|
|
|
|
|
(4,900 |
) |
|
|
3,430 |
|
|
|
(45,774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease for the year |
|
|
|
|
|
|
(7,951 |
) |
|
|
(1,077 |
) |
|
|
|
|
|
|
(9,028 |
) |
Beginning of year |
|
|
2 |
|
|
|
17,770 |
|
|
|
2,811 |
|
|
|
|
|
|
|
20,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
2 |
|
|
$ |
9,819 |
|
|
$ |
1,734 |
|
|
$ |
|
|
|
$ |
11,555 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- 83 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Cash Flows |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non- |
|
|
|
|
|
|
|
Year Ended December 31, 2005 |
|
Parent |
|
|
Subsidiaries |
|
|
Guarantor |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
Cash flows from operating activities |
|
$ |
7,566 |
|
|
$ |
33,945 |
|
|
$ |
6,297 |
|
|
$ |
(5,180 |
) |
|
$ |
42,628 |
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions of pipeline and terminal assets |
|
|
(125,801 |
) |
|
|
(2,111 |
) |
|
|
|
|
|
|
|
|
|
|
(127,912 |
) |
Additions to properties and equipment |
|
|
|
|
|
|
(3,838 |
) |
|
|
(45 |
) |
|
|
|
|
|
|
(3,883 |
) |
Investments in subsidiaries, net |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(125,802 |
) |
|
|
(5,949 |
) |
|
|
(45 |
) |
|
|
1 |
|
|
|
(131,795 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of senior notes, net
of discounts |
|
|
181,238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
181,238 |
|
Proceeds from issuance of common units, net
of underwriter discount |
|
|
45,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,100 |
|
Excess purchase price over contributed basis
of intermediate pipelines |
|
|
(71,850 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(71,850 |
) |
Contributions from (distributions to) partners |
|
|
(34,410 |
) |
|
|
1 |
|
|
|
(7,400 |
) |
|
|
7,399 |
|
|
|
(34,410 |
) |
Repayment of revolving credit agreement |
|
|
|
|
|
|
(25,000 |
) |
|
|
|
|
|
|
|
|
|
|
(25,000 |
) |
Cash distributions to minority interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,220 |
) |
|
|
(2,220 |
) |
Other financing activities, net |
|
|
(1,842 |
) |
|
|
(370 |
) |
|
|
|
|
|
|
|
|
|
|
(2,212 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
118,236 |
|
|
|
(25,369 |
) |
|
|
(7,400 |
) |
|
|
5,179 |
|
|
|
90,646 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) for the year |
|
|
|
|
|
|
2,627 |
|
|
|
(1,148 |
) |
|
|
|
|
|
|
1,479 |
|
Beginning of year |
|
|
2 |
|
|
|
15,143 |
|
|
|
3,959 |
|
|
|
|
|
|
|
19,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
2 |
|
|
$ |
17,770 |
|
|
$ |
2,811 |
|
|
$ |
|
|
|
$ |
20,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 13: Proposed Joint Ventures and Acquisitions
In November 2007, we executed a definitive agreement with Plains All American Pipeline, L.P. to
acquire a 25% joint venture interest in a new 95-mile intrastate pipeline system now under
construction by Plains, for the shipment of up to 120,000 bpd of crude oil into the Salt Lake City
area. Under the agreement, the SLC Pipeline will be owned by a joint venture company which will be
owned 75% by Plains and 25% by us. Subject to the actual cost of the SLC Pipeline, we will
purchase our 25% interest in the joint venture for an amount between $22.0 and $25.5 million in the
second quarter of 2008, when the SLC Pipeline is expected to become fully operational.
In November 2007, we announced an agreement
in principle for the acquisition of certain pipeline and tankage assets from Holly for approximately
$180.0 million. The consideration is expected to consist of $171.0 million in cash and our common units
valued at approximately $9.0 million. The assets include crude oil trunk lines that deliver crude
to Hollys Navajo Refinery in southeast New Mexico, gathering and connection pipelines located in west
Texas and New Mexico, on-site crude tankage located within the Navajo and Woods Cross refinery complexes,
a jet fuel products pipeline and terminal (terminal leased through September 2011) between Artesia and
Roswell, New Mexico, and crude oil and product pipelines that support Hollys Woods Cross Refinery.
In connection with the closing of this proposed transaction, we intend to enter into a 15-year pipelines
and tankage agreement with Holly that will contain a minimum annual revenue commitment to us from Holly.
The HLS board of directors has approved this proposed transaction, which we expect to
close in the first quarter of 2008.
On January 31, 2008, we entered into an option
agreement with Holly, granting us an option to purchase all of Hollys equity interests in a joint
venture pipeline currently under construction. The pipeline will be capable of transporting
refined petroleum products from Salt Lake City, Utah to Las Vegas, Nevada (the UNEV Pipeline).
Holly currently owns 75% of the equity interests in the UNEV Pipeline. Under this agreement, we have
an option to purchase Hollys equity interests in the UNEV Pipeline, effective for a 180-day period
commencing when the UNEV Pipeline becomes operational, at a purchase price equal to Hollys investment
in the joint venture pipeline, plus interest at 7% per annum.
- 84 -
Item 9.
Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
We have
had no change in, or disagreement with, our independent registered
public accounting firm on matters involving accounting and financial
disclosure.
Item 9A. Controls and Procedures
(a) Evaluation of disclosure controls and procedures
Our principal executive officer and principal financial officer have evaluated, as required by Rule
13a-15(b) under the Securities Exchange Act of 1934 (the Exchange Act), our disclosure controls
and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by
this annual report on Form 10-K. Based on that evaluation, the principal executive officer and
principal financial officer concluded that the design and operation of our disclosure controls and
procedures are effective in ensuring that information we are required to disclose in the reports
that we file or submit under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commissions rules and forms.
(b) Changes in internal control over financial reporting
There have been no changes in our internal control over financial reporting (as defined in Rule
13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially
affected or are reasonably likely to materially affect our internal control over financial
reporting.
See Item 8 for Managements Report on its Assessment of the Companys Internal Control Over
Financial Reporting and Report of the Registered Public Accounting Firm.
Item 9B. Other Information
There have been no events that occurred in the fourth quarter of 2007 that would need to be
reported on Form 8-K that have not been previously reported.
- 85 -
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Holly Logistic Services, L.L.C., as the general partner of HEP Logistics Holdings, L.P., our
general partner, manages our operations and activities on our behalf. Our general partner is not
elected by our unitholders. Unitholders are not entitled to elect the directors of HLS or directly
or indirectly participate in our management or operation. The sole member of HLS, which is a
subsidiary of Holly, elects our directors to serve until their death, resignation or removal. Our
general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as
general partner, for all of our debts (to the extent not paid from our assets), except for
indebtedness or other obligations that are made specifically non-recourse to it. Whenever
possible, our general partner intends to incur indebtedness or other obligations that are
non-recourse.
Three members of the board of directors of HLS serve on a conflicts committee to review specific
matters that the board believes may involve conflicts of interest. The conflicts committee
determines if the resolution of the conflict of interest is fair and reasonable to us. The members
of the conflicts committee may not be officers or employees of HLS or directors, officers, or
employees of its affiliates, and must meet the independence and experience standards established by
the New York Stock Exchange and the Exchange Act to serve on the audit committee of a board of
directors. Any matters approved by the conflicts committee will be conclusively deemed to be fair
and reasonable to us, approved by all of our partners, and not a breach by our general partner of
any duties it may owe us or our unitholders. In addition, we have an audit committee of three
independent directors that reviews our external financial reporting, selects our independent
registered public accounting firm, and reviews procedures for internal auditing and the adequacy of
our internal accounting controls. We also have a compensation committee of the three independent
directors which oversees compensation decisions for the officers of HLS, as well as the
compensation plans described below. In addition, we have an executive committee of the board
consisting of one independent director and two directors employed by Holly.
The board of directors of HLS has determined that Messrs. Darling, Pinkerton and Stengel meet the
applicable criteria for independence under the currently applicable rules of the New York Stock
Exchange and under the Exchange Act. These directors serve as the only members of our audit,
conflicts and compensation committees.
Mr. Darling has been selected to preside at regularly scheduled meetings of non-management
directors. Persons wishing to communicate with the non-management directors are invited to email
the Presiding Director at presiding.director@hollyenergypartners.com or write to: Charles
M. Darling, IV, Presiding Director, c/o Secretary, Holly Logistic Services, L.L.C., 100 Crescent
Court, Suite 1600, Dallas, Texas 75201-6915.
The board of directors of HLS held ten meetings during 2007, with the audit committee, conflicts
committee and compensation committee holding seven, sixteen and seven meetings, respectively. All
board members attended each board meeting. All committee members attended each committee meeting
for the committees on which they serve.
We are managed and operated by the directors and officers of HLS on behalf of our general partner.
Most of our operational personnel are employees of HLS.
Mr. Clifton spends approximately 25% of his time overseeing the management of our business and
affairs. Mr. Blair spends all of his time in the management of our business. The rest of our
officers devote approximately one-quarter of their time to us. Our non-management directors devote
as much time as is necessary to prepare for and attend board of directors and committee meetings.
- 86 -
The following table shows information for the current directors and executive officers of HLS.
|
|
|
|
|
|
|
Name |
|
Age |
|
Position with HLS |
Matthew P. Clifton
|
|
|
56 |
|
|
Chairman of the Board and Chief Executive Officer1 |
Bruce R. Shaw
|
|
|
40 |
|
|
Director, Senior Vice President and Chief Financial Officer |
W. John Glancy
|
|
|
65 |
|
|
Vice President, General Counsel |
David G. Blair
|
|
|
49 |
|
|
Senior Vice President |
Mark T. Cunningham
|
|
|
48 |
|
|
Vice President, Operations |
P. Dean Ridenour
|
|
|
66 |
|
|
Director1 |
Charles M. Darling, IV
|
|
|
59 |
|
|
Director234 |
Jerry W. Pinkerton
|
|
|
67 |
|
|
Director1234 |
William P. Stengel
|
|
|
59 |
|
|
Director234 |
|
|
|
1 |
|
Member of the Executive Committee
|
|
2 |
|
Member of the Conflicts Committee
|
|
3 |
|
Member of the Audit Committee
|
|
4 |
|
Member of the Compensation Committee |
Matthew P. Clifton was elected Chairman of our Board, and Chief Executive Officer in March 2004.
He has been employed by Holly for over twenty years. Mr. Clifton served as Hollys Vice President
of Economics, Engineering and Legal Affairs from 1988 to 1991, Senior Vice President of Holly
Corporation from 1991 to 1995, President of Navajo Pipeline Company, a wholly owned subsidiary of
Holly Corporation, since its inception in 1981, President of Holly Corporation from 1995 to 2005,
and has served as Chief Executive Officer of Holly Corporation since January 1, 2006. Mr. Clifton
has also served as a director of Holly Corporation since 1995.
Bruce R. Shaw was elected to our Board of Directors in April 2007 and to the position of Senior
Vice President, Chief Financial Officer in January 2008. Mr. Shaw served as Vice President,
Special Projects for Holly from September 2007 to December 2007. Prior to September 2007, Mr. Shaw
briefly left Holly in June 2007 and served as President of Standard Supply and Distributing
Company, Inc. and Bartos Industries, Ltd., two companies that are affiliated with each other in the
heating, ventilation, and air conditioning industry. Mr. Shaw previously served Holly Corporation
in various positions including Vice President of Corporate Development from February 2006 to May
2007, Vice President of Crude Purchasing and Corporate Development from February 2005 to February
2006, Vice President of Corporate Development from March 2004 to February 2005, Vice President of
Marketing and Corporate Development from November 2003 to March 2004, Vice President of Corporate
Development from October 2001 to November 2003 and Director of Corporate Development from June 1997
to January 2000. Mr. Shaw also served as Vice President, Corporate Development for HLS from August
2004 to January 2007.
W. John Glancy was elected Vice President and General Counsel in August 2004, and served as
Secretary from August 2004 to April 2005. Mr. Glancy has served as Senior Vice President and
General Counsel of Holly Corporation since September 1999. From December 1998 to September 1999,
he was Senior Vice PresidentLegal of Holly Corporation and held the office of Secretary of Holly
Corporation from April 1999 until February 2005. From 1997 through March 1999, he practiced law in
the Law Offices of W. John Glancy in Dallas. From 1972 through 1996, he was in private law
practice with several different law firms in Dallas. He also was a director of Holly Corporation
from 1975 to 1995, and for part of that period was Secretary of Holly Corporation.
David G. Blair was elected Senior Vice President in January 2007. He has been employed by Holly
for over 25 years. Mr. Blair served as Hollys Vice President responsible for Holly Asphalt
Company from February 2005 to December 2006. Mr. Blair was General Manager of the NK Asphalt
Partnership between Koch Materials Company and Navajo Refining Company from July 2000 to February
2005. Mr. Blair was named Vice President, Marketing, Asphalt & Specialty Products in October 1994.
Mr. Blair served in various positions within Holly in crude oil supply, wholesale product
marketing, and supply and trading from 1981 to 1991.
- 87 -
Mark T. Cunningham was elected Vice President of Operations in July of 2007. He has served Holly
as Senior Manager of Special Projects from December 2006 through June 2007 and as Senior Manager of
Integrity Management and EH&S from July 2004 through December 2006. Prior to joining Holly, Mr.
Cunningham served Diamond Shamrock / Ultramar Diamond Shamrock for 20 years in several engineering
and pipeline operations capacities. He began his time with Diamond Shamrock in 1983 and served
various positions including Senior Design Engineer, Superintendent of Special Projects, Regional
Manager and General Manager of Operations and Director of Operations through April 2003.
P. Dean Ridenour was elected to our Board of Directors in August 2004 and served as Vice President
and Chief Accounting Officer from January 2005 to January 2008. Mr. Ridenour served as Vice
President, Special Projects of Holly Corporation from August 2004 to December 2004 and prior to
becoming a full-time employee, provided full-time consulting services to Holly Corporation
beginning in October 2002. From April 2001 until October 2002, Mr. Ridenour was temporarily
retired. From July 1999 through April 2001, Mr. Ridenour served as Chief Financial Officer and
director of GeoUtilities, Inc., an internet-based superstore for energy, telecom and other utility
services, which was purchased by AES Corporation in March 2000. Mr. Ridenour was employed for 34
years by Ernst & Young LLP, including 20 years as an audit partner, retiring in 1997. Mr. Ridenour
is no longer an officer of HEP.
Charles M. Darling, IV was elected to our Board of Directors in July 2004. Mr. Darling has served
as President of DQ Holdings, L.L.C., a venture capital investment and consulting firm focused
primarily on opportunities in the energy industry, since August 1998. From 1997 to 1998, Mr.
Darling was the President and General Counsel, and was a Director from 1993 to 1998, of DeepTech
International, which was acquired by El Paso Energy Corp. in August 1998. Mr. Darling was also a
Director at Leviathan Gas Pipeline Company from 1993 through 1998. Prior to joining DeepTech in
1997, Mr. Darling practiced law at the law firm of Baker Botts, L.L.P., for over 20 years.
Jerry W. Pinkerton was elected to our Board of Directors in July 2004. Since December 2003, Mr.
Pinkerton has been retired. From December 2000 to December 2003, Mr. Pinkerton served as a
consultant to TXU Corp., an energy services company, with respect to accounting-related projects
principally involving financial reporting. From August 1997 to December 2000, Mr. Pinkerton served
as Controller of TXU and its U.S. subsidiaries. From August 1988 until its merger with TXU in
August 1997, Mr. Pinkerton served as the Vice President and Chief Accounting Officer of ENSERCH
Corporation/Lone Star Gas Company, a diversified energy company. Prior to joining ENSERCH, Mr.
Pinkerton was employed for 26 years as an auditor by Deloitte Haskins & Sells, a predecessor firm
of Deloitte & Touche, LLP, including 15 years as an audit partner.
William P. Stengel was elected to our Board of Directors in July 2004. Mr. Stengel has been
retired since May 2003. From 1997 to May 2003, Mr. Stengel served as Managing Director of the
global energy and mining group at Citigroup/Citibank, N.A. and was responsible for Citigroups
global relationships with U.S. multinational oil and gas companies headquartered in the United
States. From 1973 to 1997, Mr. Stengel served in various other capacities with Citigroup/Citibank,
N.A.
Compliance With Section 16(a) of the Securities Exchange Act of 1934
Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and
persons who beneficially own more than 10% of Holly Energy Partners, L.P.s units to file certain
reports with the SEC and New York Stock Exchange concerning their beneficial ownership of Holly
Energy Partners, L.P.s equity securities. Holly Energy Partners, L.P. believes that during the
year ended December 31, 2007, its officers, directors and 10% unitholders were in compliance with
applicable requirements of Section 16(a).
Audit Committee
HLSs audit committee is composed of three directors who are not officers or employees of HEP or
any of its subsidiaries or Holly Corporation or any of its subsidiaries. The board of directors of
HLS has adopted a written charter for the audit committee. The board of directors of HLS has
determined that a member of the audit committee, namely Jerry W. Pinkerton, is an audit committee
financial expert (as defined by the SEC) and has designated Mr. Pinkerton as the audit committee
financial expert.
- 88 -
The audit committee selects our independent registered public accounting firm and reviews the
professional services they provide. It reviews the scope of the audit performed by the independent
registered public accounting firm, the audit report issued by the independent auditor, HEPs annual
and quarterly financial statements, any material comments contained in the auditors letters to
management, HEPs internal accounting controls and such other matters relating to accounting,
auditing and financial reporting as it deems appropriate. In addition, the audit committee reviews
the type and extent of any non-audit work to be performed by the independent auditor and its
compatibility with their continued objectivity and independence.
Report of the Audit Committee for the Year Ended December 31, 2007
Management of Holly Logistic Services, L.L.C. is responsible for Holly Energy Partners, L.P.s
internal controls and the financial reporting process. Ernst & Young LLP, Holly Energy Partners,
L.P.s Independent Registered Public Accounting Firm for the year ended December 31, 2007, is
responsible for performing an independent audit of Holly Energy Partners, L.P.s consolidated
financial statements in accordance with the standards of the Public Company Accounting Oversight
Board and to issue a report thereon as well as to issue a report on the effectiveness of Holly
Energy Partners, L.P.s internal control over financial reporting. The audit committee monitors
and oversees these processes. The audit committee selects Holly Energy Partners, L.P.s
independent registered public accounting firm.
The audit committee has reviewed and discussed Holly Energy Partners, L.P.s audited consolidated
financial statements with management and the independent registered public accounting firm. The
audit committee has discussed with Ernst & Young LLP the matters required to be discussed by
Statement on Auditing Standards No. 61, Communications with Audit Committees. The audit
committee has received the written disclosures and the letter from Ernst & Young LLP required by
Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees, and
has discussed with Ernst & Young LLP that firms independence.
The audit committee selected Ernst & Young LLP, Independent Registered Public Accounting Firm, to
audit the books, records and accounts of the Partnership for the 2007 calendar year.
The board of directors of our general partner, upon recommendation by the audit committee, has
adopted an audit committee charter, which is available on our website at www.hollyenergy.com. The
charter requires the audit committee to approve in advance all audit and non-audit services to be
provided by our independent registered public accounting firm. All fees for audit, audit-related
and tax services as well as all other fees presented under Item 14 Principal Accountant Fees and
Services were approved by the audit committee.
Based on the foregoing review and discussions and such other matters the audit committee deemed
relevant and appropriate, the audit committee recommended to the board of directors that the
audited consolidated financial statements of Holly Energy Partners, L.P. be included in Holly
Energy Partners, L.P.s Annual Report on Form 10-K for the year ended December 31, 2007.
Members of the Audit Committee:
Jerry W. Pinkerton, Chairman
Charles M. Darling, IV
William P. Stengel
Code of Ethics
HEP has adopted a Code of Business Conduct and Ethics that applies to all officers, directors and
employees, including the companys principal executive officer, principal financial officer, and
principal accounting officer.
Available
on our website at www.hollyenergy.com are copies of our Corporate Governance Guidelines,
Audit Committee Charter, Compensation Committee Charter, and Code of Business Conduct and Ethics,
all of which also will be provided in print without charge upon written request to the Vice
President,
- 89 -
Investor Relations at: Holly Energy Partners, L.P., 100 Crescent Court, Suite 1600, Dallas, TX,
75201-6915. The Partnership intends to satisfy the disclosure requirement under Item 5.05 of Form
8-K regarding an amendment to, or waiver from, a provision of its Code of Business Conduct and
Ethics with respect to its principal financial officers by posting such information on this
website.
New York Stock Exchange Certification
In 2007, Mr. Clifton, as the Companys Chief Executive Officer, provided to the New York Stock
Exchange the annual CEO certification regarding the Companys compliance with the New York Stock
Exchanges corporate governance listing standards.
- 90 -
Item 11. Executive Compensation
DIRECTOR COMPENSATION
Directors who also serve as officers or employees of HLS or Holly do not receive additional
compensation in their capacity as directors. The only officers of HLS or Holly who also served as
directors during 2007 were Messrs. Clifton, Ridenour and Shaw. Mr. Shaw was an employee of Holly
during 2007 except between June 1 and September 16, 2007; he is now Senior Vice President and Chief
Financial Officer of Holly and HLS effective as of January 7, 2008, replacing Stephen J. McDonnell.
Although Mr. Ridenour is still an employee, he no longer serves as an officer of HLS. In July
2007, the Board of Directors implemented changes to the cash and equity components of the
compensation of non-employee directors. As of December 31, 2007, the compensation for non-employee
directors was: (a) a $50,000 annual cash retainer, payable in four quarterly installments (adjusted August 1, 2007
from $30,000 in 2006); (b) $1,500 for attendance at each in-person meeting of the Board of
Directors or a Board committee, a $1,000 meeting fee for attendance at each telephonic meeting of
the Board of Directors or a Board committee that lasts more than
thirty minutes (adjusted August 1, 2007 from a
$1,500 meeting fee for telephonic meetings lasting over two hours and a $750 meeting fee for
telephonic meetings lasting from 30 minutes to two hours in 2006), and a fee of $1,500 per day for
each day that a non-employee director attends a strategy meeting with the HLS management; (c) an
annual grant under the Holly Energy Partners, L.P. Long-Term Incentive Plan (Long-Term Incentive
Plan) of restricted HEP units equal in value to $50,000 on the date of grant, with vesting in 25%
increments every three months over the following 12 months
(adjusted August 1, 2007 from $40,000 with a vesting
period of 12 months in 2006). The Long-Term Incentive Plan grants are effective on the date they
are approved by the Board of Directors and this date varies each year. A restricted HEP unit is a
common unit subject to forfeiture until the award vests. In addition, the directors who serve as
chairpersons of the committees of the Board of Directors each receive an annual retainer of
$10,000, payable in four quarterly installments (adjusted August 1,
2007 from $7,500 for the chairpersons of the
Audit and Conflicts Committees and $5,000 for the chairperson of the Compensation Committee in
2006). In addition, each director is reimbursed for out-of-pocket expenses in connection with
attending board or committee meetings. Each director is fully indemnified by HLS for actions
associated with being a director to the extent permitted under Delaware law.
During the calendar year ending December 31, 2007, compensation was made to directors of HLS as set
forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fees Earned or |
|
Stock |
|
|
|
|
Paid in Cash |
|
Awards(1) |
|
Total |
Charles M. Darling, IV |
|
$ |
86,917 |
|
|
$ |
75,304 |
|
|
$ |
162,221 |
|
Jerry W. Pinkerton |
|
$ |
88,375 |
|
|
$ |
75,304 |
|
|
$ |
163,679 |
|
William P. Stengel |
|
$ |
88,375 |
|
|
$ |
75,304 |
|
|
$ |
163,679 |
|
Bruce R. Shaw (2) |
|
$ |
12,333 |
|
|
$ |
20,937 |
|
|
$ |
33,270 |
|
|
|
|
(1) |
|
Reflects the amount recognized in the year ended December 31, 2007 in
accordance with Statement of Financial Accounting Standards
(SFAS) No. 123(R), Share Based Payments, and includes amounts for awards granted prior to 2007. In
2007, each of the outside directors received an award of 959 restricted HEP units on
August 1, 2007 with a grant date fair value of $50,000. 240 of the 959 units vested on
November 1, 2007. The remaining restricted HEP units will vest quarterly on February
1, 2008, May 1, 2008 and August 1, 2008. The fair market value of each restricted unit
grant is measured on the grant date and is amortized over the vesting period. As of
December 31, 2007, Messrs. Darling, Pinkerton and Stengel each held 1,620 unvested
restricted units. |
|
(2) |
|
Mr. Shaw was compensated as a non-employee director between June 1, 2007 and
September 16, 2007. As of December 31, 2007, Mr. Shaw held 719 unvested restricted
units. |
COMPENSATION DISCUSSION AND ANALYSIS
This compensation discussion and analysis (CD&A) provides information about our compensation
objectives and policies for our principal executive officer, our principal financial officer and
our other most highly compensated executive officers and is intended to place in perspective the
information contained in the executive compensation tables that follow this discussion. We provide
a general description of our compensation program and specific information about its various
components. Additionally, we describe our policies relating to reimbursement to Holly for
compensation expenses. We also provide information
- 91 -
about HLS executive officer changes that became effective in January 2008. Immediately following
this CD&A is our Compensation Committee Report (the Committee Report).
Overview
HEP is managed by HLS, the general partner of HEPs general partner. HLS is a subsidiary of Holly.
The employees providing services to HEP are employed by HLS; HEP itself has no employees. As of
December 31, 2007, HLS had 106 employees that provide general, administrative and operational
services to HEP. Throughout this discussion, the following individuals are referred to as the
Named Executive Officers and are included in the Summary Compensation Table on page 100:
Matthew P. Clifton, HLSs Chairman of the Board and Chief Executive Officer;
Stephen J. McDonnell, HLSs Vice President and Chief Financial Officer (Mr. McDonnell was
replaced by Bruce R. Shaw, who became Senior Vice President and Chief Financial Officer
effective January 7, 2008);
P. Dean Ridenour served as HLSs Vice President and Chief Accounting Officer until January
7, 2008. Although Mr. Ridenour is still an employee, he no longer serves as an officer of
HLS.
David G. Blair, HLSs Senior Vice President;
Mark T. Cunningham, HLSs Vice President, Operations beginning July 1, 2007 and an HLS
employee throughout 2007; and
James G. Townsend, Vice President, Pipeline Operations until August 7, 2007, when he became
an employee of Holly.
Of the five Named Executive Officers of HEP, only Messrs. Blair and Cunningham are current
employees of HLS. Mr. Townsend was an employee of HLS until August 7, 2007 but also performed
duties for Holly throughout 2007.
Under the terms of the Omnibus Agreement, the annual administrative fee we pay to Holly increased
to $2,100,000 as of July 1, 2007 and is for the provision of general and administrative services
for our benefit, which may be increased as permitted under the Omnibus Agreement. Additionally, we
reimburse Holly for expenses incurred on our behalf. The administrative services covered by the
Omnibus Agreement include, without limitation, the costs of corporate services provided to HEP by
Holly such as accounting, information technology, human resources and in-house legal support;
office space, furnishings and equipment; and transportation of HEP executive officers on Holly
airplanes for business purposes. The partnership agreement provides that our general partner will
determine the expenses that are allocable to HEP. See Item 13, Certain Relationships and Related
Transactions of this Form 10-K Annual Report for additional discussion of our relationships and
transactions with Holly. None of the services covered by the administrative fee are assigned any
particular value individually. Although certain Named Executive Officers provide services to both
Holly and HEP, no portion of the administrative fee is specifically allocated to services provided
by the Named Executive Officers to HEP; rather, the administrative fee generally covers services
provided to HEP by Holly and HLS employees and, except as described below, there is no
reimbursement by HEP of cash compensation expenses paid by Holly or HLS to the Named Executive
Officers. With respect to equity compensation paid by HEP to the Named Executive Officers, HLS
purchases the units, and HEP reimburses HLS for the purchase price.
With respect to Mr. Townsend, we reimbursed Holly for 58% of the expenses incurred by Holly for Mr.
Townsends salary, bonus, retirement and other benefits through August 31, 2007 when Mr. Townsends
compensation was allocated 100% to Holly. As Mr. Townsend also provided services to Hollys
subsidiary, Navajo Pipeline Co., L.P. (Navajo Pipeline) through August 31, 2007, 42% of his cash
compensation and benefits for this period were charged to Navajo Pipeline. We reimbursed Holly (or
in the case of equity compensation, HLS purchased units and HEP reimbursed HLS for the cost of the
units) for 58% of the expenses incurred in providing Mr. Townsend with long-term incentive equity
- 92 -
compensation for the period from January 1, 2007 through August 31, 2007. Notwithstanding that 42%
of the costs associated with compensating Mr. Townsend were borne by Holly and not HEP during such
period, all 2007 compensation paid to Mr. Townsend by Holly, HLS and HEP is disclosed in the
tabular disclosure following this compensation discussion and analysis.
With respect to Messrs. Blair and Cunningham, we reimbursed Holly for 100% of the compensation
expenses incurred by Holly for salary, bonus, retirement and other benefits for 2007 for Messrs.
Blair and Cunningham. We reimbursed HLS for 100% of the expenses incurred in providing Messrs.
Blair and Cunningham with long-term incentive equity compensation. All compensation paid to them
is fully disclosed in the tabular disclosure following this compensation discussion and analysis.
Messrs. Clifton, McDonnell and Ridenour were compensated by HLS for the services they perform for
HLS through awards of equity-based compensation granted pursuant to the Long-Term Incentive Plan.
None of the cash compensation paid to or other benefits made available to Messrs. Clifton,
McDonnell and Ridenour by Holly was allocated to the services they provide to HLS and, therefore,
only the Long-Term Incentive Plan awards granted to them are disclosed herein.
Objectives of Compensation Program
Our compensation program is designed to attract and retain talented and productive executives who
are motivated to protect and enhance the long-term value of HEP for its unitholders. Our objective
is to be competitive with our industry and encourage high levels of performance.
The HLS Compensation Committee (the Committee), comprised entirely of independent directors,
administers the Long-Term Incentive Plan for certain HLS employees and reviewed and confirmed in February 2007 the
recommendations of the Holly Compensation Committee with regard to the total compensation of
Messrs. Clifton, McDonnell and Ridenour. The Committee determined and approved the long-term incentive
compensation to be paid to the Named Executive Officers and the compensation in addition to the long-term incentive
compensation to be paid to Mr. Blair and, during his tenure with HEP, to Mr. Townsend.
As to Mr. Blair and during his tenure with HEP, Mr. Townsend, the Committee has not adopted any formal policies for allocating compensation among salaries,
bonuses and long-term incentive compensation. The Committee attempts to balance the use of both cash and equity
compensation in the total compensation package provided to Messrs. Blair and Townsend and as to our other Named Executive officers, attempts to utilize long-term incentive compensation to build value to both HEP and its unitholders. The
Committee considers recommendations by management and many other factors in deciding on the final
compensation factors for which it has responsibility for each Named Executive Officer. The Committee does not review or approve pension benefits for Named Executive officers and all are provided the same pension benefits that are provided to Holly employees.
In February 2007, the Committee, with the assistance of management, sought to designate an
appropriate mix of cash and long-term equity incentive compensation for Messrs. Townsend and Blair
with a goal to provide sufficient current compensation to retain them, while at the same time
providing incentives to maximize long-term value for HEP and its unit holders. The Committee, with
the assistance of management, annually performs an internal review of each of the Named Executive
Officers long-term incentive compensation to determine whether the executives are being provided with equity
awards that are effective in motivating the Named Executive Officers to create long-term value for
HEP. The Committee also compares the Named Executive Officers compensation to that of similarly
situated executives in other comparable businesses. These long-term equity incentives are designed
to retain the executives during the period of time during which their performance is expected to
impact our business and reward them in accordance with the success of those long-term goals and
policies.
As part of its consideration, the Committee reviewed and discussed market data and recommendations
provided by an established, independent consulting firm specializing in executive compensation
issues. Except with respect to his own compensation, the Committee solicited the recommendations
of our Chairman of the Board and Chief Executive Officer, which the Committee considers in making
its determinations. The Committee also reviewed the total compensation provided in the previous
year in determining compensation to be paid in 2007.
Mr. Cunninghams compensation is established by Messrs. Clifton and Blair with the assistance of
the Vice President of Human Resources based upon all of the same factors used by the Committee and
- 93 -
described in this subsection. Mr. Cunninghams salary is a grade that does not require Committee
approval, so his compensation package is reviewed and approved by management instead of the
Committee. The Committee was provided with an overview of Mr.
Cunninghams compensation with opportunity for discussion.
Overview of 2007 Executive Compensation Components
For Mr. Townsend (whose compensation was for the period from January 1, 2007 through August 31,
2007) and Messrs. Blair and Cunningham (whose compensation was for the entire year), the components
of compensation in 2007 were:
|
|
|
base salary; |
|
|
|
|
annual performance-based cash incentive compensation; |
|
|
|
|
long-term equity incentive compensation; and |
|
|
|
|
retirement and other benefits. |
In 2007, the only component of compensation we provided for the other Named Executive Officers was
long-term equity incentive compensation. Because Messrs. Clifton, McDonnell, and Ridenour commit
less than half of their business time to HEP, during which time they are primarily involved in
determining the long-term business goals and policies of HEP, the Committee believes that it is
appropriate to compensate them only through long-term equity incentives. All Named Executive
Officers receiving equity awards received restricted HEP units with the exception of Mr. Clifton,
who only received an award of HEP performance units, and
Mr. Blair, who received an award of both
restricted HEP units and HEP performance units. The nature of each of these types of awards is
more fully described below.
Base Salary
The base salary for Mr. Blair was approved at the time of his promotion in late 2006 and was not
changed for 2007. The base salary for Mr. Townsend was approved in February 2007 to be effective
as of March 1, 2007. The Committee approved these salaries based on their respective positions and
levels of responsibility, individual performance, HLSs salary range for executives at their
respective levels and market practices. The Committee also reviewed competitive market data
provided by Frederick W. Cook & Associates, an independent consultant (Consultant) retained by
the Committee, relevant to the two positions.
Mr. Cunninghams salary is not established by the Committee and was established by Messrs. Blair
and Clifton and the Vice President of Human Resources in the amount set forth in the Summary
Compensation Table.
Annual Incentive Cash Bonus Compensation
The Holly Logistic Services Annual Incentive Plan (the Annual Incentive Plan) was adopted by the
HLS Board of Directors in August 2004 with the objective of motivating management and the employees
of HLS and its affiliates who perform services for HLS and HEP to collectively produce outstanding
results, encourage superior performance, increase productivity,
contribute to the health and safety goals of the Company and aid in attracting and retaining
key employees. The Committee oversees the administration of the Annual Incentive Plan, and any
potential awards granted pursuant to it are subject to final determination by the Committee that
the performance goals for the applicable periods have been achieved.
These performance criteria can include both HEP and Holly factors, given the scope of
responsibilities of our Named Executive Officers. The total bonus pool for all executives and
employees of HLS is typically determined by the Committee after the end of each year or designated
performance period, calculated pursuant to the achievement of the objective pre-established
performance criteria described above. Awards for a given year are paid in cash in the first
quarter of the following year.
- 94 -
Payment with respect to any cash bonus is contingent upon the satisfaction of the following
pre-established 2007 performance criteria:
|
|
|
A portion of the bonus is equal to a pre-established percentage of the employees base
salary and is earned only if Holly achieves its 2007 pre-tax net income (PTNI) goal of
$256,000,000. This component is subject to being adjusted to a minimum amount of 0% and a
maximum amount of two times the employees pre-established percentage. If the PTNI goal is
met, the Committee uses discretion in determining the percentage paid. Subject to the
requirement that the PTNI goal is met, the adjustment of up to two times the employees
pre-established percentage may vary from year to year in the Committees discretion. |
|
|
|
|
A portion of the bonus is equal to a pre-established percentage of the employees base
salary, and is earned only if Hollys stock price performance for the year outperforms that
of our peers. This component is subject to being adjusted to a minimum amount of 0% and a
maximum amount of two times the employees pre-established percentage. If the goal is met,
the Committee uses discretion in determining the percentage paid. Subject to the
requirement that this goal is met, the adjustment of up to two times the employees
pre-established percentage may vary from year to year in the Committees discretion. |
|
|
|
|
A portion of the bonus is equal to a pre-established percentage of the employees base
salary, based on the performance of the employees business unit versus the units budgeted
goal for 2007. Subject to the requirement that this goal is met, the adjustment of up to
two times the employees pre-established percentage may vary from year to year in the
Committees discretion. |
|
|
|
|
A portion of the bonus equal to a pre-established percentage of the employees base
salary, based on the employees individual performance over the year. This component is
subject to being adjusted to a minimum amount of 0% and a maximum amount of two times the
employees pre-established percentage. The employees individual performance for 2007 is
evaluated through an annual performance review completed in February 2008. The review
includes a written assessment provided by the employees immediate supervisor. The
assessment reviews how well the employee displays each of the following competencies: |
|
- |
|
Individual Performance |
|
|
- |
|
Integrity |
|
|
- |
|
Interpersonal Effectiveness |
|
|
|
Each one of these performance dimensions has a variety of sub-categories that are separately
reviewed. The assessment also evaluates how well the employee performed their individual
goals for 2007. |
The 2008 performance goals have not yet been established. The Committee does not believe that the
2008 goals are material in understanding the 2007 compensation.
In addition to the pre-defined performance criteria, the Committee has discretion to approve an increase or
decrease in a Named Executive Officers bonus. Increases and decreases are determined using the same factors
that are used to establish bonuses, and poor results on the indicated factors could, in the
discretion of the Committee, result in a decrease in a bonus. The Committee also considers whether conditions outside the control of the executives affected the factors. In cases where the performance
objectives described above are achieved, yet the Committee believes additional compensation is
warranted to reward an executive for outstanding performance, the Committee may award additional
bonuses in its discretion. In making the determination as to whether such discretion should be
applied (either to decrease a bonus or award additional bonuses), the Committee reviews
recommendations from management. For 2007, as in 2006, the Committee approved a discretionary
increase in some bonuses as shown in footnote 1 to the Summary Compensation Table. All bonuses
will be paid in March 2008.
The Committee also utilized the analysis of the Consultant to determine how the compensation of
Messrs. Blair, Cunningham and Townsend, including bonus payments, compared to our peers and a
market average (see the paragraph below titled Review of Market Data for further discussion).
The annual
- 95 -
incentive targets were assessed on the basis of total cash, including base salary and annual
incentive payments. The Committee believes this analysis verifies that total cash compensation to
Messrs. Blair, Cunningham and Townsend is appropriate.
The target and actual annual incentive cash bonus compensation awarded (and subsequently earned and
payable) is described in the narrative to the section titled 2007 Grants of Plan-Based Awards.
Long-Term Incentive Equity Compensation
The Long-Term Incentive Plan was adopted by the HLS Board of Directors in August 2004 with the
objective of promoting the interests of HEP by providing to management, employees and consultants
of HLS and its affiliates who perform services for HLS and HEP and its subsidiaries incentive
compensation awards that are based on units of HEP. The Long-Term Incentive Plan is also
contemplated to enhance our ability to attract and retain the services of individuals who are
essential for the growth and profitability of HEP, to encourage them to devote their best efforts
to advancing our business strategically, and to align their interests with those of our unit
holders. The Long-Term Incentive Plan is reviewed and approved by the Committee.
The Long-Term Incentive Plan contemplates four potential types of awards: restricted units,
performance units, unit options and unit appreciation rights. Since the inception of HEP, we have
awarded only restricted units and performance unit awards.
With respect to the Named Executive Officers, in determining the appropriate amount and type of
long-term incentive awards to be made, the Committee considers the amount of time devoted by each
executive to our business, the executives position and scope of responsibility, base salary and
available compensation information for executives in comparable positions in similar companies.
The awards are granted annually during the first quarter of the year, typically in February.
Our goal is to reward the creation of value and high performance with variable compensation
dependent on that performance, thus the peer data is used subjectively (and not as an objective
factor) to confirm that our executives are paid consistently with other similar companies. The
peer data allows the Committee to verify that the compensation paid to executives is appropriate.
The total compensation may be adjusted if the Committee observes material variation of the market
date (no specific formula is used to benchmark this data).
Restricted Units
A restricted unit is a common unit subject to forfeiture upon termination of employment prior to
the vesting of the award. The Committee may approve grants on the terms that it determines,
including the period during which the award will vest. Under the Long-Term Incentive Plan, the
Committee may condition vesting upon the achievement of specified financial objectives. The
restricted units will vest upon a change of control of HEP, our general partner, HLS or Holly,
unless provided otherwise by the Committee. Restricted unit holders have all the rights of a
unitholder with respect to such restricted units, including the right to receive all distributions
paid with respect to such restricted units and any right to vote with respect to the restricted
units, subject to limitations on transfer and disposition of the units during the restricted
period.
In 2007, the Named Executive Officers who were granted awards of restricted units were Messrs.
McDonnell, Ridenour, Blair, Cunningham and Townsend. One-third of these restricted unit awards
became fully vested and nonforfeitable on January 1, 2008. After December 31, 2008, two-thirds of
the restricted units will be fully vested and nonforfeitable, and all the restricted units will be
fully vested and nonforfeitable after December 31, 2009.
Performance Units
A performance unit is a notational phantom unit that entitles the grantee to receive a common unit
upon the vesting of the unit or, as may be provided in the applicable agreement between the grantee
and HLS,
- 96 -
the cash equivalent to the value of a common unit. Performance units will only be settled upon the
attainment of pre-established performance targets. The Committee may approve grants on such terms
as the Committee shall determine. The Committee approves the period over which performance units
will vest, and the Committee may base its determination upon the achievement of specified financial
objectives. As with restricted units, performance units will vest upon a change of control of HEP,
our general partner, HLS or Holly, unless provided otherwise by the Committee. Performance units
are also subject to forfeiture in the event that the executives employment or service relationship
terminates for any reason, unless and to the extent that the Committee provides otherwise.
In 2007, the only Named Executive Officers who received an award of performance units were Messrs.
Clifton and Blair. Performance units were awarded to Messrs. Clifton and Blair given their
responsibilities to HEP with respect to long-term strategy. The performance period for such award
is from January 1, 2007 through December 31, 2009. Messrs. Clifton and Blair may earn no less than
50% and no more than 150% of the performance units subject to their awards over the course of the
performance period as described more fully in the narrative accompanying the Grant of Plan Based
Awards Table. The performance units may be settled only in common units of HEP.
Acquisition of Common Units for Long-Term Incentive Equity Awards
Common units to be delivered in connection with the grant of performance unit awards may be common
units acquired by HLS on the open market, common units already owned by HLS, common units acquired
by HLS directly from us or any other person or any combination of the foregoing. We do not
currently hold treasury units. HLS is entitled to reimbursement by us for the cost of acquiring
the common units.
Review of Market Data
Market pay levels are one of many factors we consider in setting compensation for the Named
Executive Officers and we regularly compare our compensation program with market information in
regard to salary and annual incentive levels, long-term incentive award levels, and short- and
long-term incentive practices. The purpose of this analysis is to provide a frame of reference in
evaluating the reasonableness and competitiveness of compensation with the energy industry, and to
ensure that our compensation is generally comparable to companies of similar size and scope of
operations.
Market pay levels are obtained from various sources including published compensation surveys and
information taken from the SEC filings for two groups of publicly traded organizations, as compiled
by our independent compensation consultant. One benchmark group includes a number of publicly
traded master limited partnerships (MLPs) that included in 2007: Kinder Morgan Energy Partners,
L.P., Enbridge Energy Partners, L.P., TEPPCO Partners, L.P., NuStar Energy L.P. (formerly Valero
L.P.), Magellan Midstream Partners, L.P., Buckeye Energy Partners, L.P., Sunoco Logistics Partners
L.P., Inergy L.P., Crosstex Energy, LP, TC Pipelines, LP, Mark-West Energy Partners, L.P., Atlas
Pipeline Partners, L.P. and Hiland Partners, LP. Information for a broader group of energy
companies, including Holly, is also reviewed in developing our salary and incentive structures as
well as in the development of long-term equity incentive award guidelines.
Our objective is to position pay levels approximating the middle range of market practice. As
noted, however, market pay levels are only one factor considered, with pay decisions ultimately
reflecting a discretionary evaluation of individual contribution and value to HEP.
The Consultant does not have approval authority for the ultimate compensation that is provided to
employees. Instead, the Consultant provides recommendations to management by identifying areas
that do not appear to be consistent with the general practice of our peers (without setting
specific benchmarks and using a discretionary standard). The Consultant provides recommendations
regarding compensation to management and to the Committee prior to the late February or March
meetings when salaries are approved, bonuses are awarded and equity compensation is established.
- 97 -
Role of Named Executive Officers in Determining Executive Compensation
Various members of management facilitate the Committees consideration of compensation for Named
Executive Officers by providing data for the Committees review. This data includes, but is not
limited to HEPs annual budget as approved by HLSs Board of Directors, HEPs financial performance
over the course of the year versus that of its peers, performance evaluations of Named Executive
Officers, compensation provided to the Named Executive Officers in previous years, tax-related
considerations and accounting-related considerations. Management provides the Committee with
guidance as to how such data impacts pre-determined performance goals set by the Committee during
the previous year. When management considers a discretionary bonus to be appropriate for a Named
Executive Officer, it will suggest an amount and provide the Committee with managements rationale
for such bonus. Given the day-to-day familiarity that management has with the work performed by
the Named Executive Officers, the Committee values managements recommendations. However, the
Committee makes the final decision as to the compensation of HLSs Named Executive Officers. For
2007, and after consideration of managements recommendations regarding discretionary increases
in the bonuses and discussion regarding such increases, the Committee approved discretionary increases in some bonuses as shown in footnote
1 to the Summary Compensation Table.
Tax and Accounting Implications
We account for the equity compensation expense for our employees and executive officers, including
our Named Executive Officers, under the rules of SFAS 123(R), which requires us to estimate and
record an expense for each award of equity compensation over the vesting period of the award.
Accounting rules also require us to record cash compensation as an expense at the time the
obligation is accrued. As HLS is a subsidiary of Holly, a publicly-traded corporation, the
Committee is mindful of the impact that Section 162(m) of the Internal Revenue Code (the Code)
may have on compensatory deductions passed through to HLSs parent and the Committee considers this
impact when it approves compensation for the Named Executive Officers. To the extent Section
162(m) of the Code may impact the deductibility of compensation expenses, the Committee intends
generally to structure arrangements, where feasible, to minimize or eliminate the impact of the
limitations of Section 162(m) of the Code. Nevertheless, to the extent that, in the opinion of the
Committee, structuring compensatory arrangements to fully maximize a corporate deduction is not in
the best interest of HEP, either due to the need to attract or retain top talent or for any other
legitimate business reason, the Committee may approve compensation arrangements that are not
deductible.
Retirement and Benefit Plans
The cost of retirement and welfare benefits for employees of HLS are charged monthly to us by Holly
in accordance with the terms of the Omnibus Agreement. These employees participate in Hollys
Retirement Plan (a tax qualified defined benefit plan) and Hollys Thrift Plan (a tax qualified
defined contribution plan). Hollys Retirement Plan is described below in the narrative
accompanying the Pension Benefits Table.
The Thrift Plan is offered to all employees of HLS. Employees may, at their election, contribute
to the Thrift Plan 0% up to a maximum of 50% of their compensation. In 2006, employees had the
option to participate in both the Retirement Plan and the Thrift Plan. Effective January 1, 2007,
the Retirement Plan was frozen for new employees not covered by collective bargaining agreements
with labor unions, and these new employees were required to participate in the new Automatic Thrift
Plan Contribution feature under the Thrift Plan (as shown on summary compensation table). To the
extent an employee was hired prior to January 1, 2007, and elected to begin receiving the Automatic
Thrift Plan Contribution under the Thrift Plan, their participation in future benefits under the
Retirement Plan was frozen. The Automatic Thrift Plan Contribution is up to 5% of base pay subject
to applicable IRS limits and it is paid in addition to employee deferrals and employer matching
contributions under the Thrift Plan.
In 2007, for employees not covered by collective bargaining agreements with labor unions, Holly
matched employee contributions to the Thrift Plan up to 6% of their compensation. Employee
contributions that were made on a tax-deferred basis were generally limited to $15,500 per year
with employees over 50
- 98 -
years of age able to make additional tax-deferred contributions of $5,000. Prior to 2007, Hollys
contributions in the Thrift Plan did not vest until the earlier of three years of credited service
or termination of employment due to retirement, disability or death. On and after January 1, 2007,
all contributions for employees not covered by collective bargaining agreements with labor unions
are immediately vested with no waiting period.
None of Messrs. Blair, Cunningham or Townsend elected to receive the Automatic Thrift Plan
Contribution under the Thrift Plan and all remained in the Holly Retirement Plan that is discussed
below in the section titled Pension Benefits Table. Messrs. Townsend, Cunningham and Blair are
the only Named Executive Officers whose Retirement Plan and Thrift Plan benefits are charged to us
by Holly. The cost of Mr. Townsends benefits was allocated 58% to us for the period from January
1, 2007 through August 31, 2007 and the remainder of the cost was paid by Holly.
Change-in-Control Agreements
Holly has entered into Change-In-Control Agreements with Messrs. Blair, Cunningham and Townsend.
The material terms of, and the quantification of, the potential amounts payable under the
Change-in-Control Agreements are described below in the section titled Potential Payments upon
Termination or Change-in-Control. Holly provides these agreements to Messrs. Blair and
Cunningham to provide for management continuity in the event of a change of control, and to assist
in the recruitment and retention of executives. Neither we nor HLS has entered into any employment
agreements or severance agreements with any of the Named Executive Officers, other than the
change-in-control agreements described below.
Compensation Committee Report
The Compensation Committee of the Holly Logistic Services, L.L.C. Board of Directors has reviewed
and discussed this Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K
with management and, based on such review and discussion, the Compensation Committee recommended to
the Board that this Compensation Discussion and Analysis be included in this Form 10-K.
Members of the Compensation Committee:
Charles M. Darling, IV, Chairman
Jerry W. Pinkerton
William P. Stengel
Summary Compensation Table
The table below summarizes the total compensation paid or earned by each of the Named Executive
Officers in 2007. As previously noted, the cash compensation and benefits for Named Executive
Officers other than Messrs. Townsend, Cunningham and Blair were not paid by us, but rather by
Holly, and were not allocated to the services those Named Executive Officers performed for us in
2007. Information regarding the compensation paid to Messrs. Clifton, McDonnell, and Ridenour as
consideration for the services they perform for Holly will be reported in Hollys annual proxy
statement.
This space is intentionally blank.
- 99 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Compensation Table |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive Plan |
|
Change in |
|
All Other |
|
|
Name and |
|
|
|
|
|
|
|
|
|
Bonus |
|
Stock |
|
Option |
|
Compensation |
|
Pension |
|
Compensation |
|
|
Principal Position |
|
Year |
|
Salary |
|
(1) |
|
Awards (2) |
|
Awards |
|
(3) |
|
Value (4) |
|
(5) |
|
Total |
Matthew P. Clifton,
Chairman of the
Board and Chief |
|
|
2007 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
386,086 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
386,086 |
|
Executive Officer |
|
|
2006 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
286,522 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
286,522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stephen J.
McDonnell, Vice
President and |
|
|
2007 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
75,219 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
75,219 |
|
Chief Financial Officer |
|
|
2006 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
35,086 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
35,086 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
P. Dean Ridenour,
Vice President and |
|
|
2007 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
184,240 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
184,240 |
|
Chief Accounting
Officer |
|
|
2006 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
135,406 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
135,406 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David G. Blair,
Senior Vice
President |
|
|
2007 |
|
|
$ |
260,004 |
|
|
$ |
117,000 |
|
|
$ |
133,904 |
|
|
$ |
|
|
|
$ |
208,000 |
|
|
$ |
26,177 |
|
|
$ |
13,500 |
|
|
$ |
758,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark T. Cunningham,
Vice President -
Operations |
|
|
2007 |
|
|
$ |
147,148 |
(6) |
|
$ |
71,000 |
|
|
$ |
28,539 |
|
|
$ |
|
|
|
$ |
72,000 |
|
|
$ |
10,194 |
|
|
$ |
8,793 |
|
|
$ |
337,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James G. Townsend,
Vice
President |
|
|
2007 |
|
|
$ |
199,508 |
(7) |
|
$ |
40,000 |
|
|
$ |
136,952 |
|
|
$ |
|
|
|
$ |
160,000 |
|
|
$ |
51,111 |
|
|
$ |
11,970 |
|
|
$ |
599,541 |
|
Pipeline Operations |
|
|
2006 |
|
|
$ |
203,940 |
|
|
$ |
30,000 |
|
|
$ |
71,132 |
|
|
$ |
|
|
|
$ |
143,000 |
|
|
$ |
38,555 |
|
|
$ |
7,471 |
|
|
$ |
494,098 |
|
|
|
|
(1) |
|
This reflects the discretionary bonus that is in excess of the pre-established maximum
amount potentially payable pursuant to our annual incentive bonus arrangement. For 2007, Mr.
Townsends bonus was reimbursed by us in the manner set forth in footnote 7 to this chart. |
|
(2) |
|
Amounts listed represent the amount of expense recognized for financial reporting purposes in
2006 and 2007 for restricted unit and performance unit awards in
accordance with SFAS No. 123(R) and includes amounts from awards granted prior to 2007. Following SEC rules, the amounts shown
exclude the impact of estimated forfeitures related to service-based vesting conditions. See
note 6 to our consolidated financial statements for a discussion of the assumptions used in
determining the SFAS 123(R) compensation cost of these awards. The amount for Mr. Clifton and
Mr. Blair is based on an estimated payment of 125% of the performance units. No forfeitures
of equity awards to the named executive officers occurred in 2007. |
|
(3) |
|
See the narrative to the section titled 2007 Grant of Plan-Based Awards for further
information on the performance targets used to determine the amounts attributable to amounts
earned in 2007 under our Annual Incentive Plan. |
|
(4) |
|
The amounts reflect the following assumptions: |
|
|
|
|
|
|
|
December 31, 2006 |
|
December 31, 2007 |
Discount Rate:
|
|
6.00%
|
|
6.40% |
Mortality Table:
|
|
RP2000 White Collar
|
|
RP2000 White Collar |
Reserving Table:
|
|
(50% Male/ 50% Female)
|
|
(50% Male/ 50% Female) |
Retirement Age:
|
|
the later of current age
or age 62
|
|
the later of current age
or age 62 |
|
|
|
(5) |
|
This reflects matching contributions made to the Thrift Plan by HLS, which were reimbursed by
HEP. Since all Named Executive Officers elected to remain in the Holly Retirement Plan, the
only contributions are employer matching of employee contributions, subject to the limits
described in the section Retirement and Benefit Plans. |
|
(6) |
|
Mr. Cunninghams annual salary was $132,636 effective January 1, 2007, $138,612 effective
March 1, 2007 and $159,408 effective July 15, 2007. |
|
(7) |
|
Mr. Townsends annual salary was adjusted to $201,408 effective March 1, 2007 from his
previous salary of $190,000. For the period from January 1, 2007 through August 31, 2007, 42%
of Mr. Townsends salary was charged to Navajo Pipeline for services provided in 2007 by Mr.
Townsend to Navajo Pipeline and, therefore, was not reimbursed by us and 58% of this amount
was paid by HLS. However, because Mr. Townsend is not a Named Executive Officer of Holly and,
hence, the total compensation received by him (for services to both Holly and us) will not
otherwise be disclosed. We believe it is appropriate to include his full salary
notwithstanding the fact that only 58% of this amount is borne by us.
From September 1, 2007
through December 31, 2007, Mr. Townsends salary was charged 100% to Holly Corporation and was
not reimbursed by us. Mr. Townsends salary for 2006 includes a retroactive salary adjustment
for 2005 that was paid in 2006. |
- 100 -
2007 Grants of Plan-Based Awards
The amounts reflected in the table below represent three elements of compensation that we provide
to our Named Executive Officers: performance units and restricted units granted pursuant to the
Long-Term Incentive Plan, and cash bonuses awarded pursuant to the Annual Incentive Plan.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Future Payouts Under Non-Equity |
|
Estimated Future Payouts Under |
|
|
|
|
|
(j) |
|
|
|
|
|
|
|
|
Incentive Plan Awards (1) |
|
Equity Incentive Plan Awards (2) |
|
(i) |
|
Base |
|
(k) |
|
|
(b) |
|
(c) |
|
|
|
|
|
|
|
|
|
(f) |
|
|
|
|
|
(h) |
|
All other |
|
Price of |
|
Grant |
(a) |
|
Grant |
|
Thresh- |
|
(d) |
|
(e) |
|
Thresh- |
|
(g) |
|
Maximum |
|
Equity |
|
Awards |
|
Date Fair |
Name |
|
Date |
|
old |
|
Target |
|
Maximum |
|
old |
|
Target |
|
(#) |
|
Awards(3) |
|
($/Unit) |
|
Value(4) |
Matthew P. Clifton
Performance Units |
|
|
2/28/07 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
4,368 |
|
|
|
8,736 |
|
|
|
13,104 |
|
|
|
|
|
|
$ |
|
|
|
$ |
381,064 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stephen J. McDonnell
Restricted Units |
|
|
2/28/07 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,033 |
|
|
$ |
|
|
|
$ |
88,679 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
P. Dean Ridenour
Restricted Units |
|
|
2/28/07 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,066 |
|
|
$ |
|
|
|
$ |
177,359 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David G. Blair
Performance Units |
|
|
2/28/07 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
1,525 |
|
|
|
3,049 |
|
|
|
4,574 |
|
|
|
|
|
|
$ |
|
|
|
$ |
132,997 |
|
Restricted
Units Cash |
|
|
2/28/07 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,049 |
|
|
$ |
|
|
|
$ |
132,997 |
|
Incentives |
|
|
|
|
|
|
n/a |
|
|
$ |
130,002 |
|
|
$ |
260,004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark T. Cunningham
Restricted Units Cash |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
549 |
|
|
|
|
|
|
$ |
23,947 |
|
Incentives |
|
|
|
|
|
|
n/a |
|
|
$ |
47,822 |
|
|
$ |
95,644 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James G.
Townsend
(5) Restricted Units Cash |
|
|
2/28/07 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,857 |
|
|
$ |
|
|
|
$ |
124,622 |
|
Incentives |
|
|
|
|
|
|
n/a |
|
|
$ |
80,563 |
|
|
$ |
161,126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
(1) |
|
This reflects a target and maximum bonus award amounts for each Named Executive Officer equal
to the target percentages set forth above in the section titled Annual Incentive
Compensation. The maximum reflects that the employee may receive up to 200% of the target
bonus award amount. |
|
(2) |
|
The Committee approved a grant of 8,736 performance units to Mr. Clifton and 3,049
performance units to Mr. Blair, the vesting schedules of which are described in the narrative
below. |
|
(3) |
|
The Committee approved a grant of 3,049 restricted units to Mr. Blair, 549 restricted units
to Mr. Cunningham, 2033 restricted units to Mr. McDonnell, 4,066 restricted units to Mr.
Ridenour and 2,857 to Mr. Townsend, the vesting schedules of which are described in the
narrative below. |
|
(4) |
|
This reflects the price of $43.62, the closing price at the close of business on February 27,
2007, the day immediately preceding the date of grant. |
|
(5) |
|
Mr. Townsend performed work for HEP from January 1, 2007 through August 7, 2007. As
discussed in the footnotes to the Summary Compensation Table above, 58% of Mr. Townsends
costs were allocated to HEP for the period from January 1, 2007 through August 31, 2007. |
Performance Units
Under the terms of the grant of performance units to Messrs. Clifton and Blair, each of the
executives may earn from 50% to 150% of the performance units, based on the increase in HEPs cash
distributions on the common units of HEP. The performance period for the award began on January 1,
2007 and ends on December 31, 2009. Following the completion of the performance period, Messrs.
Clifton and Blair shall be entitled to a payment of a number of common units equal to the result of
multiplying their respective original grant amounts by the performance percentage set forth below:
- 101 -
|
|
|
|
|
|
|
Performance |
|
3-Year Total Increase in Cash |
|
Percentage (%) to |
|
Distributions Per Common Unit |
|
be Multiplied by |
|
above $8.10 (1) |
|
Performance Units |
|
$0.00 or less |
|
|
50 |
% |
$0.328 or less |
|
|
75 |
% |
$0.665 or less |
|
|
100 |
% |
$1.011 or less |
|
|
125 |
% |
$1.367 or more |
|
|
150 |
% |
|
|
|
(1) |
|
$8.10 represents a 3-year cumulative distribution of $2.70 per
annum, $2.70 being the distribution rate in effect at the start of the
performance period. |
In order to receive 75% of the units subject to this award, the cash distributions per unit
declared and paid in the three years ended December 31, 2009 must total $8.43 per unit. In order
to receive 100%, the distributions per unit declared and paid for the three years ended December
31, 2009 must total $8.77 per unit. In order to receive 125%, the distributions per unit declared
and paid for the three years ended December 31, 2009 must total $9.11 per unit. In order to
receive 150%, the distributions per unit declared and paid in the three years ended December 31,
2009 must total $9.47 per unit. The percentages are interpolated between points.
In the event that the employment of either Mr. Clifton or Mr. Blair terminates prior to January 1,
2010, other than due to a defined change-in-control event, death, disability or retirement, the
applicable employee will forfeit his award. The change-in-control provisions of this award are
described below under the section titled Severance and Change-in-Control Arrangements. In the
event of the death or total and permanent disability of either Mr. Clifton or Mr. Blair, as
determined by the Committee in its sole discretion, or upon either of the employees retirement
after attaining age 62 or retirement after attaining an earlier retirement age approved by the
Committee in its sole discretion, the applicable employee shall forfeit a number of units equal to
the percentage that the number of full months following the date of separation, death, disability
or retirement to the end of the performance period bears to 36. Any remaining units that are not
vested will become vested. In its sole discretion, the Committee may make a payment assuming a
performance percentage of up to 150% instead of the prorated number. As shown in the table above,
the amount shown in column (f) reflects the minimum payment amount of 50%, the amount shown in
column (g) reflects the target amount of 100% and the amount shown in column (h) reflects the
maximum payment level of 150%.
Restricted Units
Under the terms of the grants of restricted units, one-third of the restricted units will be fully
vested and nonforfeitable after December 31, 2007, two-thirds will be fully vested and
nonforfeitable after December 31, 2008, and all of the restricted units will be fully vested and
nonforfeitable after December 31, 2009. Other than due to a defined change-in-control event,
death, disability or retirement, the employee shall forfeit two-thirds of the units if his
employment is terminated after December 31, 2007 and before January 1, 2008, and one-third of the
units if his employment is terminated after December 31, 2009 and before January 1, 2010. The
change-in-control provisions of this award are described below under the section titled Severance
and Change-in-Control Arrangements. In the event of the employees death, total and permanent
disability as determined by the Committee in its sole discretion, or upon either of the employees
retirement after attaining age 62 or retirement after attaining an earlier retirement age approved
by the Committee in its sole discretion, the employee shall forfeit a number of units equal to (i)
the total award times (ii) the percentage that the period of full months beginning on the first
calendar month following the date of death, disability or retirement and ending on December 31,
2009 bears to 36. Any remaining units that are not vested will become vested. In its sole
discretion, the Committee may decide to vest all of the units in lieu of the prorated number. Each
listed employee is a unitholder with respect to all of the restricted units and has the right to
receive all distributions paid with respect to such restricted units.
- 102 -
Annual Incentive Cash Bonus Compensation
The cash bonuses that are available to the Named Executive Officers under the Annual Incentive Plan
are based upon pre-set percentages of salary, achieved by reaching certain performance levels. A
description of the pre-established performance criteria utilized in 2007 can be found above in the
CD&A under the section titled Annual Incentive Cash Bonus Compensation. The following chart
reflects the target percentages that were set for Messrs. Blair, Cunningham and Townsend for 2007
(Messrs. Clifton, McDonnell and Ridenour do not receive Non-Equity Incentive Plan Compensation) and
the actual percentages awarded to each individual:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Possible |
Name and |
|
% based on Holly |
|
% based upon |
|
Business Unit |
|
Individual |
|
Incentive |
Principal Position |
|
|