AnnuAl RepoRt2012 Edmonton Hardisty
Spokane
PADD IV
Billings
Boise
Mountain Home
Porta
Grand Forks
T
e
x
a
c
o
/
B
u
t
t
e
PADD II
Minneapolis
Burley
Casper
Guernsey
Sidney
Omaha
CHEYENNE
Express
Platte
Des Moines
Chicago
PADD I
WOODS CROSS
Salt Lake City
Denver
PADD V
Las Vegas
Cedar City
Bloomfield
Albuquerque
Moriarty
Phoenix
Tucson
NAVAJO
El Paso
Orla
J
a
y
h
a
w
k
Wichita
Kansas City
EL DORADO
Cushing
TULSA
Duncan
Wichita Falls
Abilene
Houston
PADD III
A Niche
Pure-PlAy refiNer
Pure-Play ComPetitive r efiner
• Five refineries with 443,000 barrels per stream day
Pipelines
refining capacity
HollyFrontier Corporation
443,000 capacity
12.1 complexity
HollyFrontier refineries
HEP terminals
HollyFrontier terminals
Third-party terminals
HEP pipelines
UNEV HEP
product pipeline
Third-party product
Third-party crude
Other HollyFrontier assets
HollyFrontier pipeline
Proximity to Growing North American Crude Production
All five HFC refineries sit close to production growth.
attraCtive ni Che P roduCt markets
with advantaged C rude suPPly
• Rocky Mountains, Southwest and Mid-Continent Plains states
strong investment traCk reCord
• Future growth focused on underwritten projects
• Woods Cross, El Dorado and Tulsa refineries purchased
at industry lows on a barrel basis
strong f inanC ial PerformanCe
• Industry-leading returns on capital
• Best-in-class net income per barrel crude capacity
• Track record of cash return to shareholders
• Strong Balance Sheet
heP ownershiP
• Stable cash flows from HEP through quarterly regular
and incentive distributions
• HFC owns 44% of HEP including the 2% GP interest
• HFC received approximately $64 million in cash
distributions in 2012*
*Q4 2011 through Q3 2012 quarterly LP and GP distributions,
announced and paid in 2012
2012 At A glANce
14.7%
Based on 5-year average,
calculated as stockholders’
net income/(total debt +
stockholders’ equity).
* Reflects combined
HOC and FTO financial
data for periods prior
to merger in July 2011.
*
C
f
h
C
P
m
X
s
P
k
d
o
s
t
r
n
w
o
l
v
J
l
a
on CaPital
emPloyed
(non-GAAP measure)
Avg 2008–2012
returned in
CaPital to
shareholders
Since the
July 2011 merger
Cash return
to shareholders
LTM Cash Yield – based on
January 1, 2012 opening
stock price of $24.01
Cash and
short-term
investments
in Marketable Securities
December 31, 2012
inCreased
regular
dividends
4x
feb
may
aug
nov
2012
$0.10
$0.15
$0.15
$0.20
2011
$0.075*
$0.075*
$0.0875* $0.10
*Dividends are split adjusted reflecting HFC’s two-for-one stock split announced August 3, 2011.
166best in class%$1.1BilHFC$2.4Bil12.9%
hfcDeAr StockholDerS
I am pleased to report that 2012 was an outstanding year
both operationally and financially for HollyFrontier. We deliv-
ered strong operating performance at our refineries, generated
record earnings and executed a capital return program that
included dividends to our stockholders and stock repurchases.
We are well positioned to continue building on the success
of our tremendous year.
Consistently Outstanding Financial Results
In 2012, we continued to benefit from attractive market
conditions and structural advantages that give HollyFrontier
a competitive edge in our industry. Our outstanding financial
results reflect our prudent investments in our high-complexity
refineries that resulted in our ability to process lower price
crude feedstocks that are closer to our refineries than most
refiners. Our performance also reflects our favorable geo-
graphic position that allows our refineries to be located near
the markets we serve in the middle of the country.
The numbers are terrific – in 2012 we achieved:
• Net Income attributable to HFC stockholders of $1.7 billion
• Gross refining margins of $24.89 per produced barrel
• Record operating cash flow of $1.7 billion
• One of the strongest balance sheets in our industry.
As of December 31, 2012, we had $2.4 billion in cash
and short-term investments, compared to $1.3 billion in
long-term debt.
These 2012 financial results underscore the fundamental
strength of our business and reaffirm the benefits of the
strategic plan we have successfully executed since completing
the HollyFrontier merger in 2011.
Delivering Value by Returning Capital to Stockholders
In 2012, HollyFrontier returned over $860 million to stock-
holders through regular dividends, special dividends and
share repurchases. During the year, the HollyFrontier Board
of Directors increased the Company’s regular quarterly cash
dividend by 100% – from $0.10 per share to $0.20 per share –
and approved five special dividends of $0.50 per share each.
On an annualized basis, the Company’s cash dividend yield
was approximately 7% as of year end. In addition, the Board of
Directors authorized $700 million of share repurchases during
the year, and we completed the repurchase of $210 million
worth of shares. Overall, since completing the HollyFrontier
merger in July 2011, the Company has more than doubled its
earnings and has returned over $1.1 billion in capital to stock-
holders through dividends and share repurchases.
As we look forward, we expect that the structural advantages
that are currently increasing our operating margins will
continue to drive strong free cash generation, allowing us
to maintain our strategy of providing substantial cash returns
to our stockholders.
Operational Excellence
Operations are running well across our refineries, which are
among the most complex in the industry and have the ability to
process domestic and Canadian crudes. We have reinvested
over $1 billion of cash flow generated in recent years into our
facilities, with the goal of improving our refining capabilities.
This investment in the safety, efficiency and processing
capacity of our facilities is a critical element of our mission
and values.
2
HollyFrontier Corporation 2012 Annual Report
“ 2012 financial results underscore the fundamental
strength of our business and reaffirm the benefits
of the strategic plan we have successfully executed
since completing the merger of HollyFrontier
in 2011.”
Michael C. Jennings
Operational highlights in 2012 include:
• Record throughput levels. Overall crude throughput
levels increased over 2011, with our El Dorado and
Navajo refineries reaching record annual levels of
131,400 and 93,800 BPD, respectively.
• Increased processing of heavy and sour crude.
We increased our processing of heavy and sour crude
feedstocks from 35% of our total crude slate in 2011
to 39% in 2012.
• Completion of capital improvement projects. Capital
improvement projects completed in 2012 include MSAT2/
liquid yield improvements at the Navajo and Woods Cross
refineries, a new coker charge heater at El Dorado and an
FCC flu gas scrubber at Woods Cross.
• Start-up of the UNEV Pipeline. In early 2012, the UNEV
pipeline, our 400-mile, 12-inch refined products line that
runs from Salt Lake City to Las Vegas, became fully
operational. The UNEV pipeline enables us to supply the
Las Vegas and Cedar City markets at a considerable cost
advantage to our competitors.
• Sale of 75% UNEV Pipeline interest to Holly Energy
Partners. In July 2012, we sold our 75% interest in the
UNEV Pipeline to Holly Energy Partners, our Master Limited
Partnership, for $315 million. The UNEV dropdown trans-
action reflects the synergistic nature of our refining and
related logistics operations.
• Woods Cross refinery expansion and modernization program.
We announced an agreement with Newfield Exploration
Company to supply waxy crude upon completion of the
ongoing modernization and expansion of our Woods Cross
refinery. This will provide increased capacity to serve the
important Las Vegas market through the UNEV Pipeline,
as well as our traditional customers in Salt Lake City and
the Inter-Mountain West.
Health, safety and environmental stewardship remain
our top corporate values. We continue to execute on an
expectation that “no one gets hurt” and “nothing gets
harmed” as we conduct everyday operations at all of
our facilities.
HollyFrontier’s outstanding operational performance is
the result of the dedication and efforts of the Company’s
talented employees. Our 2,500 employees do a terrific
job every day efficiently and safely running our operations.
Their hard work has enabled HollyFrontier to deliver the
outstanding results we achieved in 2012. We extend our
deepest appreciation and thanks to our employees for their
service and hard work.
In addition, we would like to thank Matthew Clifton, who retired
as Executive Chairman of HollyFrontier on January 1, 2013.
We are extremely appreciative of his 30 plus years of leadership
and service to HollyFrontier and its predecessors, and we are
pleased that he will continue as Chairman and CEO of Holly
Energy Partners.
Looking Ahead
We are excited about where we are as a company today.
Financially and operationally, HollyFrontier is firing on all
cylinders, and we believe the Company is well positioned
for the future, even when market conditions inevitably shift.
We look forward to continuing to meet our standards of
operational excellence, execute on our strategic goals
and enhance value for our stockholders.
Sincerely,
Michael C. Jennings
Chairman, Chief Executive Officer and President
3
MiD-coNtiNeNt
The Mid-Continent Region comprises our Tulsa and El Dorado refineries and has
a combined crude oil processing capacity of 260,000 BPSD.
mid-Continent s ales of r efinery ProduCed ProduCts
254,350 bP d
Crude and
feedstocks
n Sour crude oil 8%
n Sweet crude oil 70%
n Heavy sour
crude oil 14%
n Other feedstocks
and blends 8%
Product mix
n Gasolines 48%
n Diesel fuels 29%
n Jet fuels 9%
n Asphalt 2%
n Lubricants 5%
n Other 7%
SouthweSt
The Southwest Region consists of our Navajo
refinery and has a crude oil processing
capacity of 100,000 BPSD. In addition, we
manufacture and market commodity and
modified asphalt products throughout the
Southwest Region.
southwest s ales of r efinery
ProduCed ProduCts
99,160 b Pd
Crude and
feedstocks
n Sour crude oil 77%
n Sweet crude oil 2%
n Heavy sour
crude oil 12%
n Other feedstocks
and blends 9%
Product mix
n Gasolines 51%
n Diesel fuels 38%
n Asphalt 2%
n Other 9%
• Located in El Dorado, Kansas
• Located in Tulsa, Oklahoma
• Located in Artesia, New Mexico and
• 135,000 BPSD capacity and
Nelson Complexity rating of 11.8
• 125,000 BPSD capacity and
Nelson Complexity rating of 14.0
• Processes sour and heavy (Canadian)
crude oils into high-value light products
• Distributes to high-margin markets
in Colorado and Mid-Continent/
Plains states
• Processes predominantly sweet crude
oil with up to 10,000 BPD of heavy
Canadian crudes
• Distributes to the Mid-Continent states
• Markets high-value specialty lubricants
throughout North America and to
Central and South America
operated in conjunction with a refining
facility 65 miles east in Lovington,
New Mexico
• 100,000 BPSD capacity and
Nelson Complexity rating of 11.8
• Processes sour and heavy crude oils
into high-value light products
• Distributes to high-margin markets in
Arizona, New Mexico and West Texas
el d orado r efinery
tulsa r efinery
navaJo refinery
rocky MouNtAiN
The Rocky Mountain Region comprises our Cheyenne and Woods Cross refineries and
has a combined crude oil processing capacity of 83,000 BPSD.
holly eNergy
PArtNerS
Holly Energy Partners owns and operates
substantially all of the refined product
pipeline and terminalling assets that support
our refining and marketing operations in
the Mid-Continent, Southwest and Rocky
Mountain Regions of the United States.
roCky m ountain s ales of r efinery ProduCed ProduCts
77,550 b Pd
Crude and
feedstocks
n Sour crude oil 1%
n Sweet crude oil 47%
n Heavy sour
crude oil 31%
n Black wax crude oil 11%
n Other feedstocks
and blends 10%
Product mix
n Gasolines 55%
n Diesel fuels 32%
n Asphalt 5%
n Other 8%
• Located in Cheyenne, Wyoming
• Located in Woods Cross, Utah
• 52,000 BPSD capacity and
Nelson Complexity rating of 8.9
• Processes sour and heavy Canadian
(near Salt Lake City)
• 31,000 BPSD capacity and
Nelson Complexity rating of 12.5
crude oils into high-value light products
• Processes regional sweet and
• Distributes to high-margin Eastern
Rockies and Plains states
advantaged waxy crude as well
as Canadian sour crude oils
• Distributes to high-margin markets
in Utah, Idaho, Nevada, Wyoming
and eastern Washington
• 2,900 miles of crude oil and petroleum
product pipelines
• 12 million barrels of refined product
and crude oil storage
• 13 terminals and 10 rack facilities in
10 Western and Mid-Continent states
• 75% joint-venture interest in the UNEV
Pipeline – a 400-mile refined product
pipeline running from Salt Lake City,
Utah to Las Vegas, Nevada
• 25% joint venture interest in SLC
Pipeline, LLC – a 95-mile crude oil
pipeline system that serves refineries
in the Salt Lake City area
Cheyenne r efinery
woods Cross r efinery
holly energy P artners
Net iNcoMe
cASh flow
reveNueS
1
2
1
0
2
4
0
1
3
2
0
1
,
7
2
7
,
1
5
5
1
2
1
2
3
8
2
8
3
3
1
,
3
6
6
,
1
0
6
8
5
,
4
3
8
4
,
3
2
3
8
,
0
4
4
5
1
,
1
9
0
,
0
2
08
09
10
11 12
08
09
10
11 12
08
09
10
11 12
net income attributable
to hfC stockholders
$ in millions
Cash flows from
operating activities
$ in millions
revenues
$ in millions
1
1
1
1
5
1
6
2
2
2
3
3
3
4
4
2
4
5
9
1
6
7
9
6
4
0
2
5
,
3
5
0
,
6
8
2
7
1
,
6
6
7
2
,
0
5
0
3
,
6
7
5
9
,
9
2
3
,
0
1
08
09
10
11 12
08
09
10
11 12
08
09
10
11 12
refinery Production
BPD in thousands
hfC stockholders’ equity
$ in millions
total assets
$ in millions
ProDuctioN
equity
ASSetS
fiNANciAl highlightS
YEAR ENDED DECEMbER 31
Sales and other revenues
Income before income taxes
Net income attributable to HFC stockholders
Net income per common share attributable to HFC stockholders – diluted
Cash flows from operating activities
Cash flows used for capital expenditures
Total assets
HFC stockholders’ equity
Sales of refined products – barrels per day (“BPD”)
Refinery production – BPD
Employees
2011
2012
$ 15,439,528,000
$ 20,090,724,000
$
$
$
$
$
$
$
1,641,695,000
1,023,397,000
6.42
1,338,391,000
374,241,000
$
$
$
$
$
2,787,995,000
1,727,172,000
8.38
1,662,687,000
335,263,000
9,576,243,000
$ 10,328,997,000
5,204,010,000
$
6,052,954,000
340,630
331,890
2,382
443,620
442,730
2,534
4
HollyFrontier Corporation 2012 Annual Report
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________________________________________________________
FORM 10-K
_________________________________________________________________
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
OR
For the transition period from __________ to ____________
Commission File Number 1-3876
_________________________________________________________________
HOLLYFRONTIER CORPORATION
(Exact name of registrant as specified in its charter)
_________________________________________________________________
Delaware
(State or other jurisdiction of
incorporation or organization)
2828 N. Harwood, Suite 1300
Dallas, Texas
(Address of principal executive offices)
75-1056913
(I.R.S. Employer Identification No.)
75201-1507
(Zip Code)
(214) 871-3555
Registrant’s telephone number, including area code
_________________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $0.01 par value registered on the New York Stock Exchange.
Securities registered pursuant to 12(g) of the Act:
None.
_________________________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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
No
Yes
No
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
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant
was required to submit and post such files). Yes
No
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
registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-
K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the
definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
No
On June 29, 2012, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the Common Stock, par
value $0.01 per share, held by non-affiliates of the registrant was approximately $6.6 billion, based upon the closing price on the New York Stock Exchange on
such date. (This is not deemed an admission that any person whose shares were not included in the computation of the amount set forth in the preceding sentence
necessarily is an “affiliate” of the registrant.)
203,548,584 shares of Common Stock, par value $.01 per share, were outstanding on February 13, 2013.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's proxy statement for its annual meeting of stockholders to be held on May 15, 2013, which proxy statement will be filed with the Securities
and Exchange Commission within 120 days after December 31, 2012, are incorporated by reference in Part III.
Table of Content
Item
TABLE OF CONTENTS
Forward-Looking Statements
Definitions
1 and 2. Business and properties
1A. Risk Factors
1B. Unresolved staff comments
3. Legal proceedings
4. Mine safety disclosures
PART I
PART II
5. Market for Registrant's common equity, related stockholder matters and issuer
purchases of equity securities
6. Selected financial data
7. Management's discussion and analysis of financial condition and results of operations
7A. Quantitative and qualitative disclosures about market risk
Reconciliations to amounts reported under generally accepted accounting principles
8. Financial statements and supplementary data
9. Changes in and disagreements with accountants on accounting and financial disclosure
9A. Controls and procedures
9B. Other information
PART III
10. Directors, executive officers and corporate governance
11. Executive compensation
12. Security ownership of certain beneficial owners and management and related
stockholder matters
13. Certain relationships and related transactions, and director independence
14. Principal accounting fees and services
15. Exhibits, financial statement schedules
Signatures
Index to exhibits
PART IV
2
Page
3
4
6
21
30
31
32
33
34
35
50
50
54
101
101
101
101
101
101
102
102
102
103
105
Table of Content
FORWARD-LOOKING STATEMENTS
PART I
This Annual Report on Form
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 and Properties” in Items 1 and 2, “Risk Factors” in Item 1A, “Legal Proceedings” in Item 3 and “Management's
Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, are forward-looking statements. These
statements are based on management's beliefs and assumptions using currently available information and expectations as of the
date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we believe that the
expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove
to be correct. Therefore, actual outcomes and results could materially differ 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 actions of actual or potential competitive suppliers of refined petroleum products
in our markets;
the demand for and supply of crude oil and refined products;
the spread between market prices for refined products and market prices for crude oil;
the possibility of constraints on the transportation of refined products;
the possibility of inefficiencies, curtailments or shutdowns in refinery operations or pipelines;
effects of governmental and environmental regulations and policies;
the availability and cost of our financing;
the effectiveness of our capital investments and marketing strategies;
our efficiency in carrying out construction projects;
our ability to acquire refined product operations or pipeline and terminal operations on acceptable terms and to integrate
any existing or future acquired operations;
the possibility of terrorist attacks and the consequences of any such attacks;
general economic conditions; and
other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange
Commission filings.
Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are
set forth in this Form 10-K, including without limitation the forward-looking statements that are referred to above. When considering
forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Form 10-K
under “Risk Factors” in Item 1A and in conjunction with the discussion in this Form 10-K in “Management's Discussion and
Analysis of Financial Condition and Results of Operations” under the heading “Liquidity and Capital Resources.” 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
Table of Content
DEFINITIONS
Within this report, the following terms have these specific meanings:
“Alkylation” means the reaction of propylene or butylene (olefins) with isobutane to form an iso-paraffinic gasoline (inverse
of cracking).
“Aromatic oil” is long chain oil that is highly aromatic in nature that is used to manufacture tires and in the production of
asphalt.
“BPD” means the number of barrels per calendar day of crude oil or petroleum products.
“BPSD” means the number of barrels per stream day (barrels of capacity in a 24 hour period) of crude oil or petroleum
products.
“Biodiesel” means a alternative fuel produced from renewable biological resources.
“Black wax crude oil” is a low sulfur, low gravity crude oil produced in the Uintah Basin in Eastern Utah that has certain
characteristics that require specific facilities to transport, store and refine into transportation fuels.
“Catalytic reforming” means a refinery process which uses a precious metal (such as platinum) based catalyst to convert
low octane naphtha to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used
to desulfurize other refinery oils and is a primary source of hydrogen for the refinery.
“Cracking” means the process of breaking down larger, heavier and more complex hydrocarbon molecules into simpler
and lighter molecules.
“Crude distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing the vapor
slightly above atmospheric pressure turning it back to liquid in order to purify, fractionate or form the desired products.
“Ethanol” means a high octane gasoline blend stock that is used to make various grades of gasoline.
“FCC,” or fluid catalytic cracking, means a refinery process that breaks down large complex hydrocarbon molecules into
smaller more useful ones using a circulating bed of catalyst at relatively high temperatures.
“Hydrodesulfurization” means to remove sulfur and nitrogen compounds from oil or gas in the presence of hydrogen and
a catalyst at relatively high temperatures.
“Hydrogen plant” means a refinery unit that converts natural gas and steam to high purity hydrogen, which is then used in
the hydrodesulfurization, hydrocracking and isomerization processes.
“HF alkylation,” or hydrofluoric alkylation, means a refinery process which combines isobutane and C3/C4 olefins using
HF acid as a catalyst to make high octane gasoline blend stock.
“Isomerization” means a refinery process for rearranging the structure of C5/C6 molecules without changing their size or
chemical composition and is used to improve the octane of C5/C6 gasoline blendstocks.
“LPG” means liquid petroleum gases.
“Lubricant” or “lube” means a solvent neutral paraffinic product used in passenger and commercial vehicle engine oils,
specialty products for metal working or heat transfer and other industrial applications.
“MSAT2” means Control of Hazardous Air Pollutants from Mobile Sources, a rule issued by the U.S. Environmental
Protection Agency to reduce hazardous emissions from motor vehicles and motor vehicle fuels.
“MEK” means a lube process that separates waxy oil from non-waxy oils using methyl ethyl ketone as a solvent.
“MMBTU” means one million British thermal units.
4
Table of Content
“Natural gasoline” means a low octane gasoline blend stock that is purchased and used to blend with other high octane
stocks produced to make various grades of gasoline.
“Paraffinic oil” is a high paraffinic, high gravity oil produced by extracting aromatic oils and waxes from gas oil and is
used in producing high-grade lubricating oils.
“Refinery gross margin” means the difference between average net sales price and average product costs per produced
barrel of refined products sold. This does not include the associated depreciation and amortization costs. Refinery gross margin
is a non-GAAP performance measure.
“Reforming” means the process of converting gasoline type molecules into aromatic, higher octane gasoline blend stocks
while producing hydrogen in the process.
“Roofing flux” is produced from the bottom cut of crude oil and is the base oil used to make roofing shingles for the housing
industry.
“ROSE,” or “Solvent deasphalter / residuum oil supercritical extraction,” means a refinery unit that uses a light
hydrocarbon like propane or butane to extract non-asphaltene heavy oils from asphalt or atmospheric reduced crude. These
deasphalted oils are then further converted to gasoline and diesel. The remaining asphaltenes are either sold, blended to fuel oil
or blended with other asphalt as a hardener.
“Scanfiner” is a refinery unit that removes sulfur from gasoline to produce low sulfur gasoline blendstock.
“Sour crude oil” means crude oil containing quantities of sulfur greater than 0.4 percent by weight, while “sweet crude
oil” means crude oil containing quantities of sulfur equal to or less than 0.4 percent by weight.
“Vacuum distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing the
vapor below atmospheric pressure turning it back to a liquid in order to purify, fractionate or form the desired products.
“WCS” means Western Canada Select crude oil and is made up of Canadian heavy conventional and bitumen crude oils
blended with sweet synthetic and condensate diluents.
“WTI” means West Texas Intermediate and is a grade of crude oil used as a common benchmark in oil pricing. WTI is a
sweet crude oil and has a relatively low density.
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Table of Content
Items 1 and 2. Business and Properties
COMPANY OVERVIEW
References herein to HollyFrontier Corporation (“HollyFrontier”) include HollyFrontier and its consolidated subsidiaries. In
accordance with the Securities and Exchange Commission's (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-
K has been written in the first person. In this document, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and
its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person with certain exceptions.
Generally, the words “we,” “our,” “ours” and “us” include Holly Energy Partners, L.P. (“HEP”) and its subsidiaries as consolidated
subsidiaries of HollyFrontier, unless when used in disclosures of transactions or obligations between HEP and HollyFrontier or
its other subsidiaries. This document contains certain disclosures of agreements that are specific to HEP and its consolidated
subsidiaries and do not necessarily represent obligations of HollyFrontier. When used in descriptions of agreements and
transactions, “HEP” refers to HEP and its consolidated subsidiaries.
We merged with Frontier Oil Corporation (“Frontier”) on July 1, 2011. Concurrent with the merger, we changed our name from
Holly Corporation (“Holly”) to HollyFrontier and changed the ticker symbol for our common stock traded on the New York Stock
Exchange to “HFC.” Accordingly, this document includes Frontier, its consolidated subsidiaries and the operations of the merged
Frontier businesses effective July 1, 2011, but not prior to this date.
We are principally an independent petroleum refiner that produces high-value light products such as gasoline, diesel fuel, jet fuel,
specialty lubricant products, and specialty and modified asphalt. We were incorporated in Delaware in 1947 and maintain our
principal corporate offices at 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507. Our telephone number is 214-871-3555
and our internet website address is www.hollyfrontier.com. The information contained on our website does not constitute part of
this Annual Report on Form 10-K. A print 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 SEC website is available
on our website on the Investors page. Also available on our website are copies of our Corporate Governance Guidelines, Audit
Committee Charter, Compensation Committee Charter, Nominating / Corporate Governance Committee Charter, Environmental,
Health, Safety, and Public Policy 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. Our Code of Business Conduct
and Ethics applies to all of our officers, employees and directors, including our principal executive officer, principal financial
officer and principal accounting officer. Our common stock is traded on the New York Stock Exchange under the trading symbol
“HFC.”
On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination between us
and Frontier. On July 1, 2011, North Acquisition, Inc., a direct wholly-owned subsidiary of Holly, merged with and into Frontier,
with Frontier surviving as a wholly-owned subsidiary of Holly. Subsequent to the merger and following approval by HollyFrontier's
post-closing board of directors, Frontier merged with and into HollyFrontier, and HollyFrontier continued as the surviving
corporation. This merger combined the legacy Frontier refinery operations consisting of refineries in El Dorado, Kansas (the “El
Dorado Refinery”) and Cheyenne, Wyoming (the “Cheyenne Refinery”) with Holly’s legacy refinery operations to form
HollyFrontier. The aggregate equity consideration paid in connection with the merger was $3.7 billion.
On June 1, 2009, we acquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the “Tulsa West facility”) from an affiliate
of Sunoco, Inc. (“Sunoco”) for $157.8 million. On December 1, 2009, we acquired a 75,000 BPSD refinery from an affiliate of
Sinclair Oil Company (“Sinclair”) also located in Tulsa, Oklahoma (the “Tulsa East facility”) for $183.3 million. We have integrated
certain operations of the Tulsa West and East facilities (collectively, the “Tulsa Refineries”). This resulted in the Tulsa Refineries
having an integrated crude processing rate of 125,000 BPSD.
On February 29, 2008, we sold certain assets to HEP consisting of crude oil pipelines, tankage and terminal facilities supporting
our Navajo and Woods Cross Refineries. HEP is a variable interest entity (“VIE”) as defined under U.S. generally accepted
accounting principles (“GAAP”). Under GAAP, HEP's acquisition of these assets qualified as a reconsideration event whereby
we reassessed our beneficial interest in HEP. Following this transaction, we determined that our beneficial interest in HEP exceeded
50%. Therefore, we reconsolidated HEP effective March 1, 2008. Intercompany transactions with HEP are eliminated in our
consolidated financial statements.
HEP made several acquisitions between 2009 and 2012. Information on these acquisitions can be found under the “Holly Energy
Partners, L.P.” section provided later in this discussion of Items 1 and 2, “Business and Properties.”
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Table of Content
As of December 31, 2012, we:
•
•
•
•
owned and operated a petroleum refinery in El Dorado, Kansas, two refinery facilities located in Tulsa, Oklahoma, a
refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and
other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”), a refinery located
in Cheyenne, Wyoming and a refinery in Woods Cross, Utah (the “Woods Cross Refinery”);
owned and operated NK Asphalt Partners (“NK Asphalt”) which operates various asphalt terminals in Arizona and New
Mexico;
owned Ethanol Management Company (“EMC”), a products terminal and blending facility near Denver, Colorado, and
a 50% interest in Sabine Biofuels II, LLC (“Sabine Biofuels”), a biodiesel production facility located in Port Arthur,
Texas; and
owned a 44% interest in HEP, a consolidated VIE, which includes our 2% general partner interest. HEP owns and operates
logistic assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities
that principally support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain
regions of the United States and Alon USA, Inc.'s (“Alon”) refinery in Big Spring, Texas. Additionally, HEP owns a 75%
interest in UNEV Pipeline, L.L.C. (“UNEV”), which owns a 12-inch refined products pipeline from Salt Lake City, Utah
to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas (the “UNEV
Pipeline”) and a 25% interest in SLC Pipeline LLC (the “SLC Pipeline”), a 95-mile intrastate pipeline system that serves
refineries in the Salt Lake City area.
Our operations are currently organized into two reportable segments, Refining and HEP. The Refining segment includes the
operations of our El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries and NK Asphalt. The HEP segment involves
all of the operations of HEP effective March 1, 2008 (date of reconsolidation). The financial information about our segments is
discussed in Note 21 “Segment Information” in the Notes to Consolidated Financial Statements.
REFINERY OPERATIONS
Our refinery operations serve the Mid-Continent, Southwest and Rocky Mountain regions of the United States. We own and operate
five complex refineries having an aggregate crude capacity of 443,000 barrels per stream day. Each of our refineries has the
complexity to convert discounted, heavy and sour crude oils into a high percentage of gasoline, diesel and other high-value refined
products. For 2012, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented
50%, 31%, 6% and 3%, respectively, of our total refinery sales volumes.
The tables presented below and elsewhere in this discussion of our refinery operations set forth information, including non-GAAP
performance measures, about our refinery operations. The cost of products and refinery gross and net operating margins do not
include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under
“Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this
Form 10-K.
Consolidated
Crude charge (BPD) (1)
Refinery throughput (BPD) (2)
Refinery production (BPD) (3)
Sales of produced refined products (BPD)
Sales of refined products (BPD) (4)
Refinery utilization (5)
Years Ended December 31,
2011 (10)
2010
2012
415,210
453,740
442,730
431,060
443,620
315,000
340,200
331,890
332,720
340,630
221,440
234,910
225,980
228,140
232,100
93.7%
89.9%
86.5%
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Consolidated
Average per produced barrel (6)
Net sales
Cost of products (7)
Refinery gross margin
Refinery operating expenses (8)
Net operating margin
Refinery operating expenses per throughput barrel (9)
Feedstocks:
Sweet crude oil
Sour crude oil
Heavy sour crude oil
Black wax crude oil
Other feedstocks and blends
Total
Years Ended December 31,
2011 (10)
2010
2012
$
$
$
119.48
94.59
24.89
5.49
19.40
5.22
$
$
$
118.82
98.18
20.64
5.36
15.28
5.24
$
$
$
51%
22%
17%
2%
8%
100%
56%
23%
12%
2%
7%
100%
91.06
82.27
8.79
5.08
3.71
4.94
53%
35%
4%
3%
5%
100%
(1) Crude charge represents the barrels per day of crude oil processed at our refineries.
(2) Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion
units at our refineries.
(3) Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks
through the crude units and other conversion units at our refineries.
(4) Includes refined products purchased for resale.
(5) Represents crude charge divided by total crude capacity (BPSD). Effective July 1, 2011, our consolidated crude capacity increased
from 256,000 BPSD to 443,000 BPSD as a result of our merger with Frontier.
(6) Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts
reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles”
following Item 7A of Part II of this Form 10-K.
(7) Transportation, terminal and refinery storage costs billed from HEP are included in cost of products.
(8) Represents operating expenses of our refineries, exclusive of depreciation and amortization.
(9) Represents refinery operating expenses, exclusive of depreciation and amortization, divided by refinery throughput.
(10) Refining operating data for the year ended December 31, 2011 include crude oil processed and products yielded from the El Dorado
and Cheyenne Refineries for the period from July 1, 2011 through December 31, 2011 only, and averaged over the 365 days in the
year ended December 31, 2011.
Principal Products and Customers
Set forth below is information regarding our principal products.
Consolidated
Sales of produced refined products:
Gasolines
Diesel fuels
Jet fuels
Fuel oil
Asphalt
Lubricants
Gas oil / intermediates
LPG and other
Total
Years Ended December 31,
2011
2010
2012
50%
31%
6%
2%
3%
3%
—%
5%
100%
48%
32%
5%
2%
4%
3%
2%
4%
100%
49%
31%
5%
2%
3%
5%
2%
3%
100%
Light products are shipped to customers via product pipelines or are available for loading at our refinery truck facilities and
terminals. Light products are also made available to customers at various other locations via exchange with other parties.
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We have several significant customers, of which two accounted for more than 10% of our business in 2012. For the year ended
December 31, 2012, Shell Oil accounted for $2,323.6 million, or 12%, of our revenues and Sinclair accounted for $2,106.6 million,
or 10%, of our revenues. Our principal customers for gasoline include other refiners, convenience store chains, independent
marketers and retailers. Diesel fuel is sold to other refiners, truck stop chains, wholesalers and railroads. Jet fuel is sold for military
and commercial airline use. Specialty lubricant products are sold in both commercial and specialty markets. LPG's are sold to
LPG wholesalers and LPG retailers. We produce and purchase asphalt products that are sold to governmental entities, paving
contractors or manufacturers. Asphalt is also blended into fuel oil and is either sold locally or is shipped to the Gulf Coast. See
Note 23 “Significant Customers” in the Notes to Consolidated Financial Statements for additional information on our significant
customers.
Mid-Continent Region (El Dorado and Tulsa Refineries)
Facilities
The El Dorado Refinery is a high-complexity coking refinery with a 135,000 barrels per stream day capacity and the ability to
process significant volumes of heavy and sour crudes. The Tulsa West and East refinery facilities are both located in Tulsa,
Oklahoma. In 2011, we integrated certain refining processes of the Tulsa Refineries which effectively provides us with a highly
complex refining operation having a combined crude processing rate of approximately 125,000 barrels per stream day. For 2012,
gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 48%, 29%, 9% and
5%, respectively, of our Mid-Continent sales volumes.
The following table sets forth information about our Mid-Continent region operations, including non-GAAP performance measures.
Mid-Continent Region (El Dorado and Tulsa Refineries)
Crude charge (BPD) (1)
Refinery throughput (BPD) (2)
Refinery production (BPD) (3)
Sales of produced refined products (BPD)
Sales of refined products (BPD) (4)
Refinery utilization (5)
Average per produced barrel (6)
Net sales
Cost of products (7)
Refinery gross margin
Refinery operating expenses (8)
Net operating margin
Refinery operating expenses per throughput barrel (9)
Feedstocks:
Sweet crude oil
Sour crude oil
Heavy sour crude oil
Other feedstocks and blends
Total
Years Ended December 31,
2011 (10)
2010
2012
248,360
269,760
263,310
254,350
258,020
183,070
194,310
188,760
188,020
190,340
111,670
113,100
106,910
107,780
108,330
95.5%
94.8%
89.3%
$
$
$
119.19
95.77
23.42
4.83
18.59
4.55
$
$
$
119.51
99.92
19.59
5.04
14.55
4.88
$
$
$
70%
8%
14%
8%
100%
82%
4%
8%
6%
100%
90.84
83.29
7.55
4.94
2.61
4.71
92%
5%
3%
—%
100%
Footnote references are provided under our Consolidated Refinery Operating Data table on page 8.
The El Dorado Refinery is located on 1,100 acres south of El Dorado, Kansas and is a fully integrated refinery. The principal
process units at the El Dorado Refinery consist of crude and vacuum distillation; hydrodesulfurization of naphtha, kerosene, diesel,
and gas oil streams; isomerization; catalytic reforming; aromatics recovery; catalytic cracking; alkylation; delayed coking;
hydrogen production; and sulfur recovery. Refining operations began at the site in 1917 and the operating units now present include
both newly constructed units and older units that have been upgraded over the years. Supporting infrastructure includes maintenance
shops, warehouses, office buildings, a laboratory, utility facilities, and a wastewater plant (“Supporting Infrastructure”) and logistics
assets owned by HEP, which includes approximately 3.7 million barrels of tankage, a truck sales terminal, and a propane terminal.
The facility typically processes approximately 135,000 BPSD of crude oil with the capability to handle a significant volume of
heavy sour crudes.
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Table of Content
The Tulsa West facility is located on a 750-acre site in Tulsa, Oklahoma situated along the Arkansas River. The principal process
units at the Tulsa West facility consist of crude and vacuum distillation (with light ends recovery), naphtha hydrodesulfurization,
catalytic reforming, propane de-asphalting, lubes extraction, MEK dewaxing, delayed coker and butane splitter units. Most of the
operating units at the facility currently in service were built in the late 1950s and early 1960s. The refinery was reconfigured to
emphasize specialty lubricant production in the early 1990s. Tulsa West facility's Supporting Infrastructure includes approximately
3.2 million barrels of feedstock and product tankage, of which 0.4 million barrels of tankage is owned by Plains All American
Pipeline, L.P. (“Plains”).
The Tulsa East facility is located on a 466-acre site also in Tulsa, Oklahoma situated along the Arkansas River. The principal
process units at the Tulsa East facility consist of crude and vacuum distillation, naphtha hydrodesulfurization, FCC, isomerization,
catalytic reforming, alkylation, scanfiner, diesel hydrodesulfurization and sulfur units. The Tulsa East facility's Supporting
Infrastructure includes approximately 3.4 million barrels of tankage capacity on the refinery's premises, of which approximately
3.2 million barrels of tankage is owned by HEP.
Markets and Competition
The primary markets for the El Dorado Refinery's refined products are Colorado and the Plains States, which include the Kansas
City metropolitan area. The gasoline, diesel and jet fuel produced by the El Dorado Refinery are primarily shipped via pipeline
to terminals for distribution by truck or rail. We ship product via the NuStar Pipeline Operating Partnership L.P. Pipeline to the
northern Plains States, via the Magellan Pipeline Company, L.P. (“Magellan”) mountain pipeline to Denver, Colorado, and on the
Magellan mid-continent pipeline to the Plains States.
The El Dorado Refinery faces competition from other Plains States and Mid-Continent refiners, but the principal competitors for
the El Dorado Refinery are Gulf Coast refiners. Although our Gulf Coast competitors typically have lower production costs because
of economies of scale, we believe that our competitors' higher refined product transportation costs allow our El Dorado Refinery
to compete effectively in the Plains States and Rocky Mountain region with the Gulf Coast refineries.
For the year ended December 31, 2012, sales to Shell represented approximately 35% of the El Dorado Refinery's total sales and
12% of our total consolidated sales. We have an offtake agreement with Shell Oil Products US (“Shell”) under which Shell purchases
gasoline, diesel and jet fuel production of the El Dorado Refinery at market-based prices through December 2014. In 2012, we
retained and marketed 76,000 BPD of the refinery's gasoline and diesel production while the remaining production was sold to
Shell. We market gasoline and diesel in the same markets where Shell sells the refinery's products, primarily in Denver and
throughout the Plains States. Upon expiration of the offtake agreement, we intend to sell the gasoline and diesel produced by the
El Dorado Refinery in the same general markets served by Shell.
The Tulsa Refineries primarily serve the Mid-Continent region of the United States. Distillates and gasolines are primarily delivered
from the Tulsa Refineries to market via pipelines owned and operated by Magellan. These pipelines connect the refinery to
distribution channels throughout Colorado, Oklahoma, Kansas, Missouri, Illinois, Iowa, Minnesota, Nebraska and Arkansas.
Additionally, HEP's on-site truck and rail racks facilitate access to local refined product markets.
In conjunction with our acquisition of the Tulsa East facility in 2009, we entered a five-year offtake agreement through 2014 with
an affiliate of Sinclair whereby Sinclair agreed to purchase 45,000 to 50,000 BPD of gasoline and distillate products at market
prices from us to supply its branded and unbranded marketing network throughout the Midwest. Upon expiration, the offtake
agreement can be renewed by Sinclair for an additional five-year term. For the year ended December 31, 2012, sales to Sinclair
represented approximately 36% of the Tulsa Refineries total sales and 10% of our total consolidated sales.
The Tulsa Refineries' principal customers for conventional gasoline include Sinclair, other refiners, convenience store chains,
independent marketers and retailers. Sinclair and railroads are the primary diesel customers. Jet fuel is sold primarily for commercial
use. The refinery's asphalt and roofing flux products are sold via truck or railcar directly from the refineries or to customers
throughout the Mid-Continent region primarily to paving contractors and manufacturers of roofing products.
Our Tulsa West facility also produces specialty lubricant products sold in both commercial and specialty markets throughout North
America and to customers with operations in Central America and South America. The specialty lubricant products are high value
products that provide a significantly higher margin contribution to the refinery. Base oil customers include blender-compounders
who prepare the various finished lubricant and grease products sold to end users. Agricultural products are formulated as
supplemental carriers for herbicides and as Environmental Protection Agency (“EPA”) registered pesticide oils, are sold to product
formulators. Process oil customers include rubber and chemical industry customers. Specialty waxes are sold primarily to packaging
customers as coating material for paper and cardboard, and to non-packaging customers in the construction materials, adhesive
and candle-making markets. Our production represents approximately 6% of paraffinic oil capacity and 13% of wax production
capacity in the United States market and is one of four refineries of specialty aromatic oils in North America.
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Table of Content
Principal Products
Set forth below is information regarding the principal products produced at our El Dorado and Tulsa Refineries:
Mid-Continent Region (El Dorado and Tulsa Refineries)
Sales of produced refined products:
Gasolines
Diesel fuels
Jet fuels
Fuel oil
Asphalt
Lubricants
Gas oil / intermediates
LPG and other
Total
Years Ended December 31,
2011
2010
2012
48%
29%
9%
1%
2%
5%
—%
6%
100%
44%
32%
7%
—%
4%
6%
3%
4%
100%
38%
31%
8%
—%
5%
11%
4%
3%
100%
Crude Oil and Feedstock Supplies
The El Dorado Refinery is located about 125 miles, and the Tulsa Refineries are located approximately 50 miles from Cushing,
Oklahoma, a significant crude oil pipeline trading and storage hub. Local pipelines provide direct access to regional Oklahoma
crude production as well as access to United States onshore, Gulf of Mexico, Canadian and other foreign crudes. The proximity
of the refineries to the Cushing pipeline and storage hub provides the flexibility to optimize their crude slate with a wide variety
of crude oil supply options.
Both our Mid-Continent Refineries are connected via pipeline to Cushing, Oklahoma. In addition, we have a transportation services
agreement to transport up to 50,000 BPD of crude oil on the Spearhead Pipeline from Flanagan, Illinois to Cushing, Oklahoma,
enabling us to transport Canadian crude oil to Cushing for subsequent shipment to either of our Mid-Continent Refineries or to
our Navajo Refinery. The initial term of this agreement expires in 2016.
Southwest Region (Navajo Refinery)
Facilities
The Navajo Refinery has a crude oil capacity of 100,000 barrels per stream day and has the ability to process sour crude oils into
high value light products such as gasoline, diesel fuel and jet fuel. For 2012, gasoline and diesel fuel (excluding volumes purchased
for resale) represented 51% and 38%, respectively, of our Southwest sales volumes.
The following table sets forth information about our Southwest region operations, including non-GAAP performance measures.
Southwest Region (Navajo Refinery)
Crude charge (BPD) (1)
Refinery throughput (BPD) (2)
Refinery production (BPD) (3)
Sales of produced refined products (BPD)
Sales of refined products (BPD) (4)
Refinery utilization (5)
Average per produced barrel (6)
Net sales
Cost of products (7)
Refinery gross margin
Refinery operating expenses (8)
Net operating margin
Refinery operating expenses per throughput barrel (9)
Years Ended December 31,
2011 (10)
2010
2012
93,830
103,120
100,810
99,160
104,620
83,700
93,260
91,810
93,950
98,540
83,900
94,270
92,050
92,550
95,790
93.8%
83.7%
83.9%
122.62
95.70
26.92
6.07
20.85
5.84
$
$
$
118.76
98.40
20.36
5.44
14.92
5.48
$
$
$
90.37
83.12
7.25
4.95
2.30
4.86
$
$
$
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Table of Content
Southwest Region (Navajo Refinery)
Feedstocks:
Sweet crude oil
Sour crude oil
Heavy sour crude oil
Other feedstocks and blends
Total
Years Ended December 31,
2011 (10)
2010
2012
2%
77%
12%
9%
100%
3%
75%
11%
11%
100%
5%
81%
4%
10%
100%
Footnote references are provided under our Consolidated Refinery Operating Data table on page 8.
The Navajo Refinery's Artesia, New Mexico facility is located on a 561-acre site and is a fully integrated refinery with crude
distillation, vacuum distillation, FCC, ROSE (solvent deasphalter), HF alkylation, catalytic reforming, hydrodesulfurization, mild
hydrocracking, isomerization, sulfur recovery and product blending units. The operating units at the Artesia facility include newly
constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Artesia, and units that
have been operating as part of the Artesia facility (with periodic major maintenance) for many years, in some very limited cases
since before 1970. Supporting Infrastructure includes approximately 2.0 million barrels of feedstock and product tankage, of which
0.2 million barrels of tankage are owned by HEP.
The Artesia facility is operated in conjunction with a refining facility located in Lovington, New Mexico, approximately 65 miles
east of Artesia. The principal equipment at the Lovington facility consists of a crude distillation unit and associated vacuum
distillation units that were constructed after 1970. Supporting Infrastructure includes 1.1 million barrels of feedstock and product
tankage of which 0.2 million barrels of tankage are owned by HEP. The Lovington facility processes crude oil into intermediate
products that are transported to Artesia by means of three intermediate pipelines owned by HEP. These products are then upgraded
into finished products at the Artesia facility. The combined crude oil capacity of the Navajo Refinery facilities is 100,000 BPSD
and it typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, gas oil and naphtha.
Markets and Competition
The Navajo Refinery primarily serves the southwestern United States market, which has historically experienced a high growth
rate, including the metropolitan areas of El Paso, Texas; Albuquerque, Moriarty and Bloomfield, New Mexico; Phoenix and Tucson,
Arizona; and portions of northern Mexico. Our products are shipped through HEP's pipelines from Artesia, New Mexico to El
Paso, Texas and from El Paso to Albuquerque and to Mexico via products pipeline systems owned by Plains and from El Paso to
Tucson and Phoenix via a products pipeline system owned by Kinder Morgan's subsidiary, SFPP, L.P. (“SFPP”). In addition,
petroleum products from the Navajo Refinery are transported to markets in northwest New Mexico and to Moriarty, New Mexico,
near Albuquerque, via HEP's pipelines running from Artesia to San Juan County, New Mexico. We have refined product storage
through our pipelines and terminals agreement with HEP at terminals in El Paso, Texas; Tucson, Arizona; and Artesia, Moriarty
and Bloomfield, New Mexico.
El Paso Market
The El Paso market for refined products is currently supplied by a number of area and gulf coast refiners and pipelines. Area
refiners include Navajo, WRB Refining, LLC (“WRB”) (a joint venture between Phillips 66 and EnCana Corp.), Valero, Alon and
Western Refining. Pipelines serving this market are owned by Magellan, NuStar Energy L.P. and HEP. Refined products from the
Gulf Coast are transported via Magellan pipelines, including Magellan's Longhorn Pipeline acquired in 2009.
Arizona Market
The Arizona market for refined products is currently supplied by a number of refiners via pipelines and trucks. Refiners include
companies located in west Texas, eastern New Mexico, northern New Mexico, the Gulf Coast and the West Coast. Magellan's
Longhorn Pipeline delivers refined products from the Texas Gulf Coast to El Paso and, through interconnections with third-party
common carrier pipelines, into the Arizona market.
New Mexico Markets
The Artesia, Albuquerque, Moriarty and Bloomfield markets are supplied by a number of refiners via pipelines and trucks. Refiners
include Navajo, Valero, Western Refining, Alon and WRB.
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We use a common carrier pipeline out of El Paso to serve the Albuquerque market. In addition, HEP leases from Mid-America
Pipeline Company, L.L.C., a pipeline between White Lakes, New Mexico and the Albuquerque vicinity and Bloomfield, New
Mexico. The lease agreement currently runs through 2017, and HEP has options to renew for two ten-year periods. HEP owns and
operates a 12-inch pipeline from the Navajo Refinery to the leased pipeline as well as terminalling facilities in Bloomfield, which
is located in the northwest corner of New Mexico, and in Moriarty, which is 40 miles east of Albuquerque. These facilities permit
us to ship light products to the Albuquerque and Santa Fe, New Mexico areas as well as into southern Colorado and northern
Arizona.
Principal Products
Set forth below is information regarding the principal products produced at our Navajo Refinery:
Southwest Region (Navajo Refinery)
Sales of produced refined products:
Gasolines
Diesel fuels
Jet fuels
Fuel oil
Asphalt
LPG and other
Total
Years Ended December 31,
2011
2010
2012
51%
38%
—%
6%
2%
3%
100%
52%
34%
1%
6%
4%
3%
100%
57%
32%
3%
4%
2%
2%
100%
Crude Oil and Feedstock Supplies
The Navajo Refinery is situated near the Permian Basin, an area that has historically and continues to have abundant supplies of
crude oil available both for regional users and for export to other areas. We purchase crude oil from independent producers in
southeastern New Mexico and west Texas as well as from major oil companies. The crude oil is gathered through HEP's pipelines,
our tank trucks and through third-party crude oil pipeline systems for delivery to the Navajo Refinery.
The Navajo Refinery also has access to a wide variety of crude oils available at Cushing, Oklahoma via HEP's Roadrunner Pipeline
that connects to Centurion Pipeline L.P. and Spearhead Pipeline at Cushing, Oklahoma. In 2010, the Navajo Refinery began
processing heavy sour crude oil transported from Cushing through these pipelines.
We also purchase volumes of isobutane, natural gasoline and other feedstocks to supply the Navajo Refinery from sources in Texas
and the Mid-Continent area that are delivered to our region on a common carrier pipeline owned by Enterprise Products, L.P.
Ultimately all volumes of these products are shipped to the Artesia refining facilities on HEP's intermediate pipelines running
from Lovington to Artesia. From time to time, we purchase gas oil, naphtha and light cycle oil from other oil companies for use
as feedstock.
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)
Facilities
The Cheyenne Refinery has a crude oil capacity of 52,000 barrels per stream day and the Woods Cross Refinery has a crude oil
capacity of 31,000 barrels per stream day. The Cheyenne Refinery processes heavy Canadian crudes as well as local sweet crudes
such as that produced from the Bakken shale and similar resources. The Woods Cross Refinery processes regional sweet and black
wax crude as well as Canadian sour crude oils into high value light products. For 2012, gasoline and diesel fuel (excluding volumes
purchased for resale) represented 55% and 32%, respectively, of our Rocky Mountain sales volumes.
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The following table sets forth information about our Rocky Mountain region operations, including non-GAAP performance
measures.
Rocky Mountain Region (Cheyenne and Woods Cross
Refineries)
Crude charge (BPD) (1)
Refinery throughput (BPD) (2)
Refinery production (BPD) (3)
Sales of produced refined products (BPD)
Sales of refined products (BPD) (4)
Refinery utilization (5)
Average per produced barrel (6)
Net sales
Cost of products (7)
Refinery gross margin
Refinery operating expenses (8)
Net operating margin
Refinery operating expenses per throughput barrel (9)
Feedstocks:
Sweet crude oil
Sour crude oil
Heavy sour crude oil
Black wax crude oil
Other feedstocks and blends
Total
Years Ended December 31,
2011 (10)
2010
2012
73,020
80,860
78,610
77,550
80,980
48,230
52,630
51,320
50,750
51,750
25,870
27,540
27,020
27,810
27,980
88.0%
84.3%
83.5%
$
$
$
116.44
89.29
27.15
6.91
20.24
6.63
$
$
$
116.37
91.33
25.04
6.41
18.63
6.18
$
$
$
47%
1%
31%
11%
10%
100%
52%
1%
24%
15%
8%
100%
94.26
75.54
18.72
6.09
12.63
6.15
59%
—%
6%
30%
5%
100%
Footnote references are provided under our Consolidated Refinery Operating Data table on page 8.
The Cheyenne Refinery facility is located on a 255-acre site and is a fully integrated refinery with crude distillation, vacuum
distillation, coking, FCCU, HF alkylation, catalytic reforming, hydrodesulfurization of naphtha and distillates, butane
isomerization, hydrogen production, sulfur recovery and product blending units. The operating units at the Cheyenne Refinery
include both newly constructed units and older units that have been upgraded over the years. Supporting Infrastructure includes
approximately 1.9 million barrels of feedstock and product tankage, of which 1.8 million barrels of tankage are owned by HEP.
The Woods Cross Refinery facility is located on a 200-acre site and is a fully integrated refinery with crude distillation, solvent
deasphalter, FCC, HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending
units. The operating units at the Woods Cross Refinery include newly constructed units, older units that have been relocated from
other facilities, upgraded and re-erected in Woods Cross, and units that have been operating as part of the Woods Cross facility
(with periodic major maintenance) for many years, in some very limited cases since before 1950. Supporting Infrastructure includes
approximately 1.5 million barrels of feedstock and product tankage, of which 0.2 million barrels of tankage are owned by HEP.
The facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane and gas oil over its 31,000 BPSD
capacity.
We own and operate 4 miles of hydrogen pipeline that connects the Woods Cross Refinery to a hydrogen plant located at Chevron's
Salt Lake City Refinery. Additionally, HEP owns and operates 12 miles of crude oil and refined products pipelines that allows us
to connect our Woods Cross Refinery to common carrier pipeline systems.
We plan to expand the Woods Cross refinery capacity to 45,000 BPSD at a cost of approximately $225.0 million. The expansion
is expected to be completed in late 2014. The expansion scope includes the relocation / revamp of crude, fluid catalytic cracking,
and polymerization units from a subsidiary of Western Refining Inc.'s (“Western”) Bloomfield, New Mexico refinery to Woods
Cross as well an expansion of the Woods Cross diesel hydrotreater. We have a definitive agreement with Western for the purchase
of the Bloomfield units.
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In conjunction with the expansion, we signed a 10-year, 20,000 BPD crude oil supply agreement with Newfield Exploration
Company. This agreement, which commences upon completion of the expansion, will supply black and yellow wax crude oil
produced in the nearby Uinta Basin to the Woods Cross Refinery, which currently has capacity to process approximately 10,000
BPD of these crudes. Upon completion of this expansion, the Woods Cross Refinery will be able to process approximately 24,000
BPD of waxy Utah crudes. This expansion and crude oil supply agreement, and expected completion timeline, are subject to
HollyFrontier successfully obtaining the necessary permits and regulatory approvals.
Markets and Competition
The Cheyenne Refinery primarily markets its products in eastern Colorado, including metropolitan Denver, eastern Wyoming and
western Nebraska. Because of the location of the Cheyenne Refinery, we are able to sell a significant portion of its diesel from
the truck rack at the refinery, thus eliminating transportation costs. Pipeline shipments from the Cheyenne Refinery are on the
Plains pipeline serving Denver and Colorado Springs, Colorado and HEP's pipeline to Sidney, Nebraska.
Denver Market
The most competitive market for the Cheyenne Refinery is the Denver metropolitan area. Three other refineries supply the Denver
market, Wyoming refineries near Rawlins and in Casper owned by Sinclair and a refinery in Denver owned by Suncor. Five product
pipelines also supply Denver, including three from outside the region. Typically products shipped in from other regions bear higher
transportation costs. The Suncor refinery has lower product transportation costs than we do; however, we have lower crude oil
transportation costs because the Cheyenne Refinery is located 88 miles south of Guernsey, Wyoming, the main hub and crude oil
trading center for the Rocky Mountain region. Moreover, unlike Sinclair and Suncor, we only sell our products to the wholesale
market. We believe this gives us an advantage because all of the Cheyenne Refinery's principal competitors have retail outlets and
we do not directly compete with independent retailers of gasoline and diesel.
Utah Market
The Woods Cross Refinery's primary market is Utah, which is currently supplied by a number of local refiners and the Pioneer
Pipeline. In addition to our Woods Cross Refinery, local area refiners include Chevron, Tesoro, Big West and Silver Eagle. Other
refiners that ship via the Pioneer Pipeline include Sinclair, ExxonMobil and Phillips 66. We estimate that the four refineries that
compete with our Woods Cross Refinery have a combined capacity to process approximately 150,000 BPD of crude oil. The five
Utah refineries collectively supply an estimated 70% of the gasoline and distillate products consumed in the states of Utah and
Idaho, with the remainder imported from refineries in Wyoming and Montana via the Pioneer Pipeline owned jointly by Sinclair
and Phillips 66. Approximately 40% - 45% of the gasoline and diesel fuel produced by our Woods Cross Refinery is sold through
a network of Phillips 66 branded marketers under a long-term supply agreement.
Idaho, Wyoming, Eastern Washington and Nevada Markets
We supply a small percentage of the refined products consumed in the combined Idaho, Wyoming, eastern Washington and Nevada
markets. Our Woods Cross Refinery ships refined products over Chevron's common carrier pipeline system to numerous terminals,
including HEP's terminals at Boise and Burley, Idaho and Spokane, Washington and to terminals at Pocatello and Boise, Idaho
and Pasco, Washington that are owned by Northwest Terminalling Pipeline Company. We sell to branded and unbranded customers
in these markets. In 2012, we began shipping refined products to Las Vegas, Nevada via the UNEV Pipeline. The majority of the
Las Vegas, Nevada market for refined products is supplied by various West Coast refiners and suppliers via Kinder Morgan's
CalNev common carrier pipeline system.
Principal Products
Set forth below is information regarding the principal products produced at our Cheyenne and Woods Cross Refineries:
Rocky Mountain Region (Cheyenne and Woods Cross
Refineries)
Sales of produced refined products:
Gasolines
Diesel fuels
Jet fuels
Fuel oil
Asphalt
LPG and other
Total
Years Ended December 31,
2011
2010
2012
55%
32%
—%
2%
5%
6%
100%
56%
31%
1%
1%
6%
5%
100%
63%
30%
1%
1%
3%
2%
100%
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Crude Oil and Feedstock Supplies
Crude oil is transported to the Cheyenne Refinery from suppliers in Canada, Nebraska, North Dakota and Montana via common
carrier pipelines owned by Kinder Morgan, Plains All American Pipeline and Suncor Energy, as well as by truck. The Woods Cross
Refinery currently obtains crude oil from suppliers in Canada, Wyoming, Utah and Colorado as delivered via common carrier
pipelines that originate in Canada, Wyoming and Colorado. In 2009, we also began receiving crude oil via the SLC Pipeline, a
joint venture common carrier pipeline in which HEP owns a 25% interest. Supplies of black wax crude oil are shipped via truck.
NK Asphalt Partners
We manufacture and market commodity and modified asphalt products in Arizona, New Mexico, Oklahoma, Kansas, Missouri,
Texas and northern Mexico. We have three manufacturing facilities located in Glendale, Arizona; Albuquerque, New Mexico; and
Artesia, New Mexico. Our Albuquerque and Artesia facilities manufacture modified hot asphalt products and commodity emulsions
from base asphalt materials provided by our refineries and third-party suppliers. Our Glendale facility manufactures modified hot
asphalt products from base asphalt materials provided by our refineries and third-party suppliers. Our products are shipped via
third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government
projects.
Other Assets
We own Ethanol Management Company, a 25,000 BPD products terminal and blending facility located near Denver, Colorado.
We also own a 50% joint venture interest in Sabine Biofuels II, LLC, a 30 million gallon per year biodiesel production facility
located near Port Arthur, Texas.
HOLLY ENERGY PARTNERS, L.P.
HEP is a Delaware limited partnership that trades on the New York Stock Exchange under the trading symbol “HEP.” HEP was
formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support our refining
and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States.
HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing
certain pipeline capacity to Alon, by charging fees for terminalling refined products and other hydrocarbons and by storing and
providing other services at its storage tanks and terminals. HEP does not take ownership of products that it transports or terminals;
therefore, it is not directly exposed to changes in commodity prices.
HEP's recent acquisitions (2009 through 2012) are summarized below:
2012 Acquisition
UNEV Interest Transaction
On July 12, 2012, HEP acquired from us our 75% interest in UNEV. We received consideration consisting of $260.0 million in
cash and 1.0 million HEP common units. UNEV owns the UNEV Pipeline, a 12-inch refined products pipeline running from Salt
Lake City, Utah to Las Vegas, Nevada together with terminal facilities in Cedar City, Utah and North Las Vegas. The UNEV
Pipeline was completed in late 2011 and became operational during the first quarter of 2012.
2011 Acquisition
Legacy Frontier Pipeline and Tankage Asset Transaction
On November 9, 2011, HEP acquired from us certain tankage, loading rack and crude receiving assets located at our El Dorado
and Cheyenne Refineries. We received non-cash consideration consisting of promissory notes with an aggregate principal amount
of $150.0 million and 3.8 million HEP common units.
2010 Acquisition
Tulsa East / Lovington Storage Asset Transaction
On March 31, 2010, HEP acquired from us certain storage assets for $93.0 million, consisting of hydrocarbon storage tanks having
approximately 2.0 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at our Tulsa East
facility and an asphalt loading rack facility located at our Navajo Refinery facility located in Lovington, New Mexico.
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2009 Acquisitions
Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, HEP acquired from Sinclair storage tanks having approximately 1.4 million barrels of storage capacity and
loading racks at what is now our Tulsa East facility for $79.2 million.
Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, HEP acquired our two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch
crude oil pipeline (the “Roadrunner Pipeline”) that connects our Navajo Refinery Lovington facility to a terminus of Centurion
Pipeline L.P.'s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects
HEP's New Mexico crude oil gathering system to our Navajo Refinery Lovington facility (the “Beeson Pipeline”).
Tulsa West Loading Racks Transaction
On August 1, 2009, HEP acquired from us, certain truck and rail loading/unloading facilities located at our Tulsa West facility for
$17.5 million. The racks load refined products and lube oils produced at the Tulsa West facility onto rail cars and/or tanker trucks.
Lovington-Artesia Pipeline Transaction
On June 1, 2009, HEP acquired our newly constructed, 16-inch intermediate pipeline for $34.2 million that runs 65 miles from
our Navajo Refinery's crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery located in
Artesia, New Mexico.
SLC Pipeline Joint Venture Interest
On March 1, 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly
owned with Plains. HEP's capitalized joint venture contribution was $25.5 million.
Rio Grande Pipeline Sale
On December 1, 2009, HEP sold its 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise
Products Partners LP for $35.0 million.
Transportation Agreements
Agreements with HEP
HEP serves our refineries under long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through
2026. Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on
HEP's pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP including UNEV
(a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments
on July 1 at a rate based upon the percentage change in Producer Price Index (“PPI”) or Federal Energy Regulatory Commission
(“FERC”) index. As of December 31, 2012, these agreements result in minimum annualized payments to HEP of $217.2 million.
Since HEP is a consolidated VIE, our transactions with HEP including the transactions discussed above and fees paid under our
transportation agreements with HEP and UNEV, a consolidated subsidiary of HEP, are eliminated and have no impact on our
consolidated financial statements.
Agreement with Alon
HEP has a 15-year pipelines and terminals agreement with Alon expiring in 2020, under which Alon has agreed to transport on
HEP's pipelines and throughput through its terminals, volumes of refined products that results in a minimum level of annual
revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but will
not decrease below the initial tariff rate. Also, HEP has a capacity lease agreement with Alon under which Alon leases space on
HEP's Orla to El Paso pipeline for the shipment of up to 15,000 barrels of refined product per day. The terms under this agreement
expire in 2018 through 2022.
As of December 31, 2012, HEP's assets include:
Pipelines
•
approximately 810 miles of refined product pipelines, including 340 miles of leased pipelines, that transport gasoline,
diesel and jet fuel principally from our Navajo Refinery in New Mexico to our 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 Alon's Big Spring refinery in
Texas to its customers in Texas and Oklahoma;
•
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•
•
•
•
•
•
three 65-mile pipelines that transport intermediate feedstocks and crude oil from our Navajo Refinery crude oil distillation
and vacuum facilities in Lovington, New Mexico to our petroleum refinery facilities in Artesia, New Mexico;
approximately 960 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and
Oklahoma that deliver crude oil to our Navajo Refinery;
approximately 10 miles of refined product pipelines that support our Woods Cross Refinery located near Salt Lake City,
Utah;
gasoline and diesel connecting pipelines that support our Tulsa East facility;
five intermediate product and gas pipelines between the Tulsa East and Tulsa West facilities; and
crude receiving assets located at our Cheyenne Refinery.
Refined Product Terminals and Refinery Tankage
•
•
•
•
•
•
•
•
four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona,
with an aggregate capacity of approximately 1,300,000 barrels, that are integrated with HEP's refined product pipeline
system that serves our 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 approximately 500,000 barrels, that are integrated with HEP's refined product pipelines that serve Alon's Big
Spring, Texas refinery;
a refined product loading rack facility at each of our El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries,
heavy product / asphalt loading rack facilities at our Tulsa East facility, Navajo Refinery Lovington facility and Cheyenne
Refinery, LPG loading rack facilities at our El Dorado Refinery, Tulsa West facility and Cheyenne Refinery, lube oil
loading racks at our Tulsa West facility and crude oil Leased Automatic Custody Transfer (“LACT”) units located at our
Cheyenne Refinery;
a leased jet fuel terminal in Roswell, New Mexico;
on-site crude oil tankage at our Tulsa, Navajo, Cheyenne and Woods Cross Refineries having an aggregate storage capacity
of approximately 1,100,000 barrels; and
on-site crude oil, refined and intermediate product tankage at our El Dorado, Tulsa and Cheyenne Refineries having an
aggregate storage capacity of approximately 8,200,000 barrels.
Additionally, HEP owns a 75% interest in UNEV, which owns the UNEV Pipeline, a 12-inch refined products pipeline from Salt
Lake City, Utah to Las Vegas, Nevada together with terminal facilities in the Cedar City, Utah and North Las Vegas areas, and a
25% interest in SLC Pipeline LLC, a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.
ADDITIONAL OPERATIONS AND OTHER INFORMATION
Corporate Offices
We lease approximately 60,000 square feet for our principal corporate offices in Dallas, Texas. The lease for our principal corporate
offices expires in 2021. Functions performed in the Dallas office include overall corporate management, refinery and HEP
management, planning and strategy, corporate finance, crude acquisition, logistics, contract administration, marketing, investor
relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.
Employees and Labor Relations
As of December 31, 2012, we had 2,534 employees, of which 851 are currently covered by collective bargaining agreements
having various expiration dates between 2015 and 2018. We consider our employee relations to be good.
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Regulation
Refinery and pipeline operations are subject to numerous federal, state and local laws regulating the discharge of substances into
the environment or otherwise relating to the protection of the environment. Permits are required under these laws for the operation
of our refineries, pipelines and related facilities, and these permits are subject to revocation, modification and renewal. Over the
years, there have been and continue to be ongoing communications, including notices of violations, and discussions about
environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to
operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will
continue to have an impact on our operations, the results of operations, and our capital requirements. We believe that our current
operations are in substantial compliance with applicable federal, state, and local environmental laws, regulations, and permits.
Our operations and many of the products we manufacture are subject to certain requirements of the Federal Clean Air Act (“CAA”)
as well as related state and local laws and regulations. Certain CAA regulatory programs applicable to our refineries require capital
expenditures for the installation of certain air pollution control devices. Additionally, the EPA has the authority under the CAA to
modify the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with
their final use. Subsequent rulemaking authorized by the CAA or similar laws, or new agency interpretations of existing laws and
regulations, may necessitate additional expenditures in future years.
Also, we are subject to the EPA's new Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”) regulations on
gasoline that impose reductions in the benzene content of our produced gasoline. Our Tulsa, Navajo and Woods Cross Refineries
currently purchase benzene credits to meet these requirements. Our remaining refineries become subject to the regulation on
January 1, 2014. Recently completed capital projects at our Tulsa, Navajo and Woods Cross Refineries and capital projects planned
for completion at our Cheyenne Refinery in 2013 will reduce the amount of benzene credits that we need to purchase. If economically
justified, we could implement additional benzene reduction projects to eliminate the need to purchase benzene credits.
The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 prescribe certain percentages of renewable
fuels (e.g., ethanol and biofuels) that, where required, must be blended into our produced gasoline and diesel. Additional changes
in fuel standards to reduce vehicle emissions are expected to be proposed in 2013. These new requirements, other requirements
of the CAA, and other presently existing or future environmental regulations may, where required, cause us to make substantial
capital expenditures and purchase credits at significant cost to enable our refineries to produce products that meet applicable
requirements.
Further regulatory requirements have emerged from concerns over the potential climate impacts of certain "greenhouse gases"
such as carbon dioxide and methane. In response to a statutory directive, the EPA has promulgated rules requiring the reporting
of greenhouse gas emissions. In 2010, the EPA promulgated regulations applying construction and operating permit requirements
under the CAA's Prevention of Significant Deterioration and Title V programs to sources with potential greenhouse gas emissions
above certain threshold levels. The EPA has also announced its intention to issue a New Source Performance Standard directly
regulating greenhouse gas emissions from refineries. Proposals both expanding and limiting the EPA's authority in this area continue
to be considered in Congress. Litigation challenging the EPA's authority over greenhouse gas emissions also is pending in federal
court. The U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) decided in 2012 to uphold the rules, but
petitions for U.S. Supreme Court review are expected.
Our operations are also subject to the Federal Clean Water Act (“CWA”), the Federal Safe Drinking Water Act (“SDWA”) and
comparable state and local requirements. The CWA, the SDWA and analogous laws prohibit any discharge into surface waters,
ground waters, injection wells and publicly-owned treatment works except in conformance with legal authorization, such as pre-
treatment permits and National Pollutant Discharge Elimination System (“NPDES”) permits, issued by federal, state and local
governmental agencies. NPDES permits and analogous water discharge permits are valid for a maximum of five years and must
be renewed.
We generate wastes that may be subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state and
local requirements. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and
non-hazardous wastes.
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The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes
liability, without regard to fault or the legality of the original conduct, on certain classes of persons, including the current and past
owner or operator of the disposal site or sites from which there is a release of a “hazardous substance,” as well as persons that
disposed of or arranged for the disposal or treatment of the hazardous substances at the site or sites. Under CERCLA, such persons
may be subject to joint and several liability for such costs as the cost of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources. In the course of our historical operations, as well as in our
current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance”
and some of which may have been disposed of at sites that may be subject to cleanup and cost recovery actions under CERCLA
by a government entity or other third party. Similarly, locations now owned or operated by us, where third parties have disposed
such hazardous substances in the past, may also be subject to cleanup and cost recovery actions under CERCLA. Under CERCLA,
liable parties may seek contribution from other liable parties to share in the costs of cleanup. Some states have enacted laws similar
to CERCLA which impose similar responsibilities and liabilities on responsible parties. It is also not uncommon for neighboring
landowners and other third parties to file claims under state law for personal injury and property damage allegedly caused by
hazardous substances or other pollutants released into the environment.
As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits
involving environmental matters. These matters include soil and water contamination, air pollution, personal injury and property
damage allegedly caused by substances which we manufactured, handled, used, released or disposed of.
We currently have environmental remediation projects that relate to recovery, treatment and monitoring activities resulting from
past releases of refined product and crude oil into the environment. As of December 31, 2012, we had an accrual of $88.9 million
related to such environmental liabilities.
We are and have been the subject of various state, federal and private proceedings and inquiries relating to compliance with
environmental regulations and conditions, including those discussed above. Compliance with current and future environmental
regulations is expected to require additional expenditures, including expenditures for investigation and remediation, which may
be significant, at our refineries and at pipeline transportation facilities. To the extent that future expenditures for these purposes
are material and can be reasonably determined, these costs are disclosed and accrued, if applicable.
Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety,
training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations.
Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.
Health and environmental legislation and regulations change frequently. We cannot predict what additional health and
environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or
regulations will be administered or interpreted with respect to our operations. Compliance with more stringent laws or regulations
or adverse changes in the interpretation of existing laws or regulations by government agencies could have an adverse effect on
our financial position and the results of our operations and could require substantial expenditures for the installation and operation
of systems and equipment that we do not currently possess.
Insurance
Our operations are subject to hazards of operations, including fire, explosion and weather-related perils. We maintain various
insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against
certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify
such expenditures.
We have a risk management oversight committee that is made up of members from our senior management. This committee
oversees our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified
risks that may adversely affect the achievement of our goals.
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Item 1A. Risk Factors
Investing in us involves a degree of risk, including the risks described below. Our operating results have been, and will continue
to be, affected by a wide variety of risk factors, many of which are beyond our control, that could have adverse effects on profitability
during any particular period. 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 or
results of operations could be materially and adversely affected.
The prices of crude oil and refined products materially affect our profitability, and are dependent upon many factors that are
beyond our control, including general market demand and economic conditions, seasonal and weather-related factors, regional
and grade differentials and governmental regulations and policies.
Among these factors is the demand for crude oil and refined products, which is largely driven by the conditions of local and
worldwide economies as well as by weather patterns and the taxation of these products relative to other energy sources.
Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, also have a significant
impact on our activities. Operating results can be affected by these industry factors, product and crude pipeline capacities, changes
in transportation costs, accidents or interruptions in transportation, competition in the particular geographic areas that we serve,
and factors that are specific to us, such as the success of particular marketing programs and the efficiency of our refinery operations.
The demand for crude oil and refined products can also be reduced 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, a shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider
adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by
manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel.
We do not produce crude oil and must purchase all our crude oil, the price of which fluctuates based upon worldwide and local
market conditions. Our profitability depends largely on the spread between market prices for refined petroleum products and crude
oil prices. This margin is continually changing and may fluctuate significantly from time to time. Crude oil and refined products
are commodities whose price levels are determined by market forces beyond our control. For example, the reversal of certain
existing pipelines or the construction of certain new pipelines transporting additional crude oil or refined products to markets that
serve competing refineries could affect the market dynamic that has allowed us to take advantage of favorable pricing. Additionally,
due to the seasonality of refined products markets and refinery maintenance schedules, results of operations for any particular
quarter of a fiscal year are not necessarily indicative of results for the full year. In general, prices for refined products are influenced
by the price of crude oil. Although an increase or decrease in the price for crude oil may result in a similar increase or decrease
in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined
products. The effect of changes in crude oil prices on operating results therefore depends in part on how quickly refined product
prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in
refined product prices, a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil
prices, or a substantial or prolonged decrease in demand for refined products could have a significant negative effect on our earnings
and cash flow. Also, crude oil supply contracts are generally short-term contracts with market-responsive pricing provisions. We
purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Price level changes during the
period between purchasing feedstocks and selling the manufactured refined products from these feedstocks could have a significant
effect on our financial condition and results of operations.
We may not be able to successfully execute our business strategies to grow our business. Further, if we are unable to complete
capital projects at their expected costs or in a timely manner, if we are unsuccessful in integrating the operations of assets we
acquire, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations,
or cash flows could be materially and adversely affected.
One of the ways we may grow our business is through the construction of new refinery processing units (or the purchase and
refurbishment of used units from another refinery) and the expansion of existing ones. Projects are generally initiated to increase
the yields of higher-value products, increase the amount of lower cost crude oils that can be processed, increase refinery production
capacity, meet new governmental requirements, or maintain the operations of our existing assets. Additionally, our growth strategy
includes projects that permit access to new and/or more profitable markets. The construction process involves numerous regulatory,
environmental, political, and legal uncertainties, most of which are not fully within our control, including:
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denial or delay in issuing requisite regulatory approvals and/or permits;
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compliance with or liability under environmental regulations;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires,
spills) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
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• market-related increases in a project's debt or equity financing costs; and/or
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nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with
a project.
For example, there may be a delay in obtaining the necessary permits or regulatory approvals for the expansion at the Woods Cross
refinery, or our request for the necessary permits or regulatory approvals may be denied. If we are unable to complete capital
projects at their expected costs or in a timely manner our financial condition, results of operations, or cash flows could be materially
and adversely affected. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as
well as affect our ability to supply certain products we make. In addition, our revenues may not increase immediately upon the
expenditure of funds on a particular project. For instance, if we build a new refinery processing unit, 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 capital investments may not achieve our expected investment return, which
could adversely affect our financial condition or results of operations.
Our forecasted internal rates of return are also based upon our projections of future market fundamentals which are not within our
control, including changes in general economic conditions, available alternative supply and customer demand.
An additional component of our growth strategy is to selectively acquire complementary assets for our refining operations in order
to increase earnings and cash flow. Our ability to do so will be dependent upon a number of factors, including our ability to identify
attractive acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain
financing to fund acquisitions and to support our growth, and other factors beyond our control. Risks associated with acquisitions
include those relating to:
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diversion of management time and attention from our existing business;
challenges in managing the increased scope, geographic diversity and complexity of operations and inefficiencies that
may result therefrom;
difficulties in integrating the financial, technological and management standards, processes, procedures and controls of
an acquired business with those of our existing operations;
liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification
or insurance;
greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for
investments to improve operating results;
difficulties or delays in achieving anticipated operational improvements or benefits;
incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and
issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders.
Any acquisitions that we do consummate may have adverse effects on our business and operating results.
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We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital
markets. This may hinder or prevent us from meeting our future capital needs.
The domestic and global financial markets and economic conditions are disrupted and volatile from time to time due to a variety
of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic
conditions and uncertainty in the financial services sector. In addition, the fixed-income markets have experienced periods of
extreme volatility, which negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and
equity capital markets has increased substantially at times while the availability of funds from these markets diminished
significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending
counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional
investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and
reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit
facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot
be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is
available only on unfavorable terms, we may be unable to meet our obligations as they come due or we may be required to sell
assets. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions or
construction projects, take advantage of other business opportunities or respond to competitive pressures, comply with regulatory
requirements, or meet our short-term or long-term working capital requirements, any of which could have a material adverse effect
on our revenues and results of operations. Failure to comply with regulatory requirements in a timely manner or meet our short-
term or long-term working capital requirements could subject us to regulatory action.
We may incur significant costs to comply with new or changing environmental, energy, health and safety laws and regulations,
and face potential exposure for environmental matters.
Refinery and pipeline operations are subject to federal, state and local laws regulating, among other things, the generation, storage,
handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the
environment, waste management, and characteristics and composition of gasoline and diesel fuels, and other matters otherwise
relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines
and related operations, and these permits are subject to revocation, modification and renewal or may require operational changes,
which may involve significant costs. Furthermore, a violation of permit conditions or other legal or regulatory requirements could
result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or refinery shutdowns. In addition, major
modifications of our operations due to changes in the law could require changes to our existing permits or expensive upgrades to
our existing pollution control equipment, which could have a material adverse effect on our business, financial condition, or results
of operations. Over the years, there have been and continue to be ongoing communications, including notices of violations, and
discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result
in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and
permits will continue to have an impact on our operations, results of operations and capital requirements.
As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits
involving environmental matters. The matters include soil and water contamination, air pollution, personal injury and property
damage allegedly caused by substances which we manufactured, handled, used, released or disposed.
We are and have been the subject of various state, federal and private proceedings relating to environmental regulations, conditions
and inquiries. Current and future environmental regulations are expected to require additional expenditures, including expenditures
for investigation and remediation, which may be significant, at our facilities. To the extent that future expenditures for these
purposes are material and can be reasonably determined, these costs are disclosed and accrued.
Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety,
training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations.
Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.
Failure to appropriately manage occupational health and safety risks associated with our business could also adversely impact
employees, communities, stakeholders, our reputation and our results of operations.
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We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the
future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. However,
new environmental laws and regulations, including new regulations relating to alternative energy sources and the risk of global
climate change, new interpretations of existing laws and regulations, increased governmental enforcement or other developments
could require us to make additional unforeseen expenditures. The EPA has begun regulating certain emissions of greenhouse gases,
or “GHGs,” (including carbon dioxide, methane and nitrous oxides) from large stationary sources like refineries under the authority
of the CAA, and it is possible that Congress could pass federal legislation that creates a comprehensive GHG regulatory program,
either directly or indirectly, such as via a federal renewal energy standard. Also, new federal or state legislation or regulatory
programs that restrict emissions of GHGs in areas where we conduct business could adversely affect demand for our products and
our results of operations.
The costs of environmental and safety regulations are already significant and compliance with more stringent laws or regulations
or adverse changes in the interpretation of existing regulations by government agencies could have an adverse effect on the financial
position and the results of our operations and could require substantial expenditures for the installation and operation of systems
and equipment that we do not currently possess.
From time to time, new federal energy policy legislation is enacted by the U.S. Congress. For example, in December 2007, the
U.S. Congress passed the Energy Independence and Security Act, which, among other provisions, mandates annually increasing
levels for the use of renewable fuels such as ethanol, commencing in 2008 and escalating for 15 years, as well as increasing energy
efficiency goals, including higher fuel economy standards for motor vehicles, among other steps. These statutory mandates may
have the impact over time of offsetting projected increases in the demand for refined petroleum products in certain markets,
particularly gasoline. In the near term, the new renewable fuel standard presents ethanol production and logistics challenges for
both the ethanol and refining industries and may require additional capital expenditures or expenses by us to accommodate increased
ethanol use. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum
products in ways that cannot be predicted.
For additional information on regulations and related liabilities or potential liabilities affecting our business, see “Regulation”
under Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings.”
The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the
refined products we produce.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to
public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the
earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations
to restrict emissions of GHGs under existing provisions of the federal CAA. The EPA also adopted two sets of rules regulating
GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of
which may require permits for emissions of GHGs from certain large stationary sources. The EPA’s rules relating to emissions of
GHGs from large stationary sources of emissions were upheld by the D.C. Circuit, but numerous parties are expected to seek U.S.
Supreme Court review of that decision in 2013. The EPA has also adopted rules requiring the reporting of GHG emissions from
specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis. The EPA has also
announced its intention to issue a New Source Performance Standard directly regulating GHG emissions from refineries.
In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost
one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development
of GHG emission inventories and/or regional GHG cap and trade programs. These cap and trade programs generally work by
requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing
plants, to acquire and on an annual basis surrender emission allowances. The number of allowances available for purchase is
reduced over time in an effort to achieve the overall GHG emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating
costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new
regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and
thereby reduce demand for, the refined products that we produce. Consequently, legislation and regulatory programs to reduce
emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.
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In addition, some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate
changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other
climatic events. If any such events were to occur, they could have an adverse effect on our financial condition and results of
operations.
We may be subject to information technology system failures, network disruptions and breaches in data security.
Information technology system failures, network disruptions (whether intentional by a third party or due to natural disaster),
breaches of network or data security, or disruption or failure of the network system used to monitor and control pipeline operations
could disrupt our operations by impeding our processing of transactions, our ability to protect customer or company information
and our financial reporting. Our computer systems, including our back-up systems, could be damaged or interrupted by power
outages, computer and telecommunications failures, computer viruses, internal or external security breaches, events such as fires,
earthquakes, floods, tornadoes and hurricanes, and/or errors by our employees. There can be no assurance that a system failure or
data security breach will not have a material adverse effect on our financial condition and results of operations.
To successfully operate our petroleum refining facilities, we are required to expend significant amounts for capital outlays and
operating expenditures.
The refining business is characterized by high fixed costs resulting from the significant capital outlays associated with refineries,
terminals, pipelines and related facilities. We are dependent on the production and sale of quantities of refined products at refined
product margins sufficient to cover operating costs, including any increases in costs resulting from future inflationary pressures
or market conditions and increases in costs of fuel and power necessary in operating our facilities. Furthermore, future major
capital investment, various environmental compliance related projects, regulatory requirements or competitive pressures could
result in additional capital expenditures, which may not produce a return on investment. Such capital expenditures may require
significant financial resources that may be contingent on our access to capital markets and commercial bank loans. Additionally,
other matters, such as regulatory requirements or legal actions, may restrict our access to funds for capital expenditures.
Our refineries consist of many processing units, a number of which have been in operation for many years. One or more of the
units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled
turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the
units are not operating. We have taken significant measures to expand and upgrade units in our refineries by installing new
equipment and redesigning older equipment to improve refinery capacity. The installation and redesign of key equipment at our
refineries involves significant uncertainties, including the following: our upgraded equipment may not perform at expected
throughput levels; operating costs of the upgraded equipment may be higher than expected; the yield and product quality of new
equipment may differ from design and/or specifications and redesign, modification or replacement of the equipment may be
required to correct equipment that does not perform as expected, which could require facility shutdowns until the equipment has
been redesigned or modified. Any of these risks associated with new equipment, redesigned older equipment, or repaired equipment
could lead to lower revenues or higher costs or otherwise have a negative impact on our future financial condition and results of
operations.
In addition, we expect to execute turnarounds at our refineries, which involve numerous risks and uncertainties. These risks include
delays and incurrence of additional and unforeseen costs. The turnarounds allow us to perform maintenance, upgrades, overhaul
and repair of process equipment and materials, during which time all or a portion of the refinery will be under scheduled downtime.
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, power failures, mechanical failures and other events beyond our control. These
events might result in a loss of equipment or life, injury, or extensive property damage or destruction of property, as well as a
curtailment or an interruption in our operations and may affect our ability to meet marketing commitments. We maintain significant
insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage
generally does not apply unless a business interruption exceeds 45 days. If any refinery were to experience an interruption in
operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance)
because of lost production and repair costs.
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The availability of adequate insurance may be affected by conditions in the insurance market over which we have no control,
resulting in the inability 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 or, in some instances, certain insurance
could become unavailable or available only for reduced amounts of coverage. We could suffer losses for uninsurable or uninsured
risks or in amounts in excess of our existing insurance coverage. The occurrence of an event that is not fully covered by insurance
could have a material adverse effect on our business, financial condition and results of operations.
The energy industry is highly capital intensive, and the entire or partial loss of individual facilities can result in significant costs
to both industry companies, such as us, and their insurance carriers. In recent years, several large energy industry claims have
resulted in significant increases in the level of premium costs and deductible periods for participants in the energy industry. As a
result of large energy industry claims, insurance companies that have historically participated in underwriting energy-related
facilities may discontinue that practice or demand significantly higher premiums or deductible periods to cover these facilities. If
significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, or if other adverse
conditions over which we have no control prevail in the insurance market, we may be unable to obtain and maintain adequate
insurance at reasonable cost. In addition, we cannot assure you that our insurers will renew our insurance coverage on acceptable
terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. Further, our
underwriters could have credit issues that affect their ability to pay claims. The unavailability of full insurance coverage to cover
events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results
of operations.
Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell
our products could adversely affect our earnings and profitability.
We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of
their geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors
may be better able to withstand volatile market conditions, to obtain crude oil in times of shortage and to bear the economic risks
inherent in all areas of the refining industry.
We are not engaged in petroleum exploration and production activities and do not produce any of the crude oil feedstocks used at
our refineries. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain
of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets.
Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset
losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand
periods of depressed refining margins or feedstock shortages.
In recent years there have been several refining and marketing consolidations or acquisitions between entities competing in our
geographic market. These transactions could increase the future competitive pressures on us.
The markets in which we compete may be impacted by competitors' plans for expansion projects and refinery improvements that
could increase the production of refined products in our areas of operation and significantly affect our profitability.
In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our
industrial, commercial and individual consumers. The more successful these alternatives become as a result of governmental
regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the impact on pricing and
demand for our products and our profitability. There are presently significant governmental and consumer pressures to increase
the use of alternative fuels in the United States.
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A material decrease in the supply of crude oil available to our refineries could significantly reduce our production levels.
To maintain or increase production levels at our refineries, we must continually contract for crude oil supplies from third parties.
A material decrease in crude oil production from the fields that supply our 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 available to
our refineries. In addition, any prolonged disruption of a significant pipeline that is used in supplying crude oil to our refineries
or the potential operation of a new, converted or expanded crude oil pipeline that transports crude oil to other markets could result
in a decline in the volume of crude oil available to our refineries. Such an event could result in an overall decline in volumes of
refined products processed at our refineries and therefore a corresponding reduction in our cash flow. In addition, the future growth
of our operations will depend in part upon whether we can contract for additional supplies of crude oil at a greater rate than the
rate of natural decline in our currently connected supplies. If we are unable to secure additional crude oil supplies of sufficient
quality or crude pipeline expansion to our refineries, we will be unable to take full advantage of current and future expansion of
our refineries' production capacities.
A disruption to or proration of the refined product distribution systems we utilize could negatively impact our profitability.
We utilize various common carrier or other third party pipeline systems to deliver our products to market. The key systems utilized
by Cheyenne, El Dorado, Navajo, Woods Cross, and Tulsa are Rocky Mountain, NuStar Energy, SFPP and Plains, Chevron, and
Magellan, respectively. All five refineries also utilize systems owned by HEP. If these key pipelines or their associated tanks and
terminals become inoperative or decrease the capacity available to us, we may not be able to sell our product, or we may be required
to hold our product in inventory or supply products to our customers through an alternative pipeline or by rail or additional tanker
trucks from the refinery, all of which could increase our costs and result in a decline in profitability.
The potential operation of new or expanded refined product transportation pipelines could impact the supply of refined products
to our existing markets.
The refined product transportation pipelines that also supply the markets supplied by the Navajo Refinery include Longhorn,
Kinder Morgan, Plains, HEP, and NuStar Energy. The Longhorn Pipeline is a common carrier pipeline that supplies the El Paso
market with refined products from refineries as distant as the Texas Gulf Coast. Flying J formerly owned the Longhorn Pipeline
prior to its bankruptcy in 2008. In addition to supplying Arizona markets from El Paso, Kinder Morgan also supplies Arizona
markets from the West Coast. The Plains pipeline currently supplies New Mexico markets from El Paso. In addition, NuStar Energy
LP and HEP own pipelines into the El Paso and New Mexico markets.
The refined product transportation pipelines that also supply the markets supplied by the Woods Cross Refinery include Chevron,
Pioneer, and Yellowstone Pipelines. The Chevron system transports products from Salt Lake City to Idaho and eastern Washington.
The Pioneer Pipeline transports products from Wyoming and Montana refineries into Salt Lake City. The Yellowstone Pipeline
transports products from Montana refineries into eastern Washington.
The refined product transportation pipelines that also supply the markets supplied by the Tulsa and El Dorado Refineries include
Magellan, Explorer, and Kaneb Pipelines. The Explorer Pipeline transports refined products from Gulf Coast refineries to Tulsa
where it interconnects with Magellan prior to proceeding to the Chicago area. The Kaneb Pipeline transports refined products
from northern Texas, Oklahoma, and Kansas refineries to markets in Kansas, Nebraska, Iowa, North Dakota, and South Dakota.
These markets are in close proximity to markets supplied by the Magellan system.
The refined product transportation pipelines that also supply the markets supplied by the Cheyenne Refinery include Rocky
Mountain, Magellan Mountain, Conoco, Medicine Bow, and Nustar Pipelines. The Rocky Mountain Pipeline System which
transports the Cheyenne Refinery's products to Denver also transports refined products from Wyoming and further north to
Cheyenne and Denver. The Medicine Bow pipeline delivers refined products from Sinclair Wyoming. The Magellan Mountain
pipeline delivers refined products directly from Kansas but those products may be supplied all the way from the Gulf Coast. The
Conoco and Nustar pipelines bring products in from the Texas panhandle.
The expansion of any of these pipelines, the conversion of existing pipelines into refined products, or the construction of a new
pipeline into our markets could negatively impact the supply of refined products in our markets and our profitability.
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We depend upon HEP for a substantial portion of the crude supply and distribution network that serve our refineries and we
own a significant equity interest in HEP.
We currently own a 44% interest in HEP, including the 2% general partner interest. HEP operates a system of crude oil and
petroleum product pipelines, distribution terminals and refinery tankage in Arizona, Idaho, Kansas, New Mexico, Oklahoma,
Texas, Utah, Washington and Wyoming. HEP generates revenues by charging tariffs for transporting petroleum products and crude
oil through its pipelines, by leasing certain pipeline capacity to Alon, by charging fees for terminalling refined products and other
hydrocarbons and storing and providing other services at its terminals. HEP serves our refineries in New Mexico, Utah, Wyoming,
Kansas and Oklahoma under several long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through
2026. Furthermore, our financial statements include the consolidated results of HEP. HEP is subject to its own operating and
regulatory risks, including, but not limited to:
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its reliance on its significant customers, including us;
competition from other pipelines;
environmental regulations affecting pipeline operations;
operational hazards and risks;
pipeline tariff regulations affecting the rates HEP can charge;
limitations on additional borrowings and other restrictions due to HEP's debt covenants; and
other financial, operational and legal risks.
The occurrence of any of these risks could directly or indirectly affect HEP's as well as our financial condition, results of operations
and cash flows as HEP is a consolidated VIE. Additionally, these risks could affect HEP's ability to continue operations which
could affect their ability to serve our supply and distribution network needs.
For additional information about HEP, see “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.” For risks
related to HEP's business, see Item 1A of HEP's Annual Report on Form 10-K for the fiscal year ended December 31, 2012.
We are exposed to the credit risks, and certain other risks, of our key customers and vendors.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We derive a significant portion
of our revenues from contracts with key customers.
If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some
of our customers may be highly leveraged and subject to their own operating and regulatory risks. In addition, nonperformance
by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability
to successfully conduct our business.
Any substantial increase in the nonpayment and/or nonperformance by our customers or vendors could have a material adverse
effect on our results of operations and cash flows.
Terrorist attacks, and the threat of terrorist attacks or domestic vandalism, have resulted in increased costs to our business.
Continued global hostilities or other sustained military campaigns may adversely impact our results of operations.
The long-term impacts 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, are 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.
Future terrorist attacks could lead to even stronger, more costly initiatives or regulatory requirements. Uncertainty surrounding
continued global hostilities 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. In addition, disruption or significant increases in energy prices could result in
government-imposed price controls. Any one of, or a combination of, these occurrences could have a material adverse effect on
our business, financial condition and results of operations.
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.
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Our petroleum business' financial results are seasonal and generally lower in the first and fourth quarters of the year, which
may cause volatility in the price of our common stock.
Demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal
increases in highway traffic and road construction work. As a result, our results of operations for the first and fourth calendar
quarters are generally lower than for those for the second and third quarters. The effects of seasonal demand for gasoline are
partially offset by seasonality in demand for diesel fuel, which in the Southwest region of the United States is generally higher in
winter months as east-west trucking traffic moves south to avoid winter conditions on northern routes. However, unseasonably
cool weather in the summer months and/or unseasonably warm weather in the winter months in the markets in which we sell our
petroleum products could have the effect of reducing demand for gasoline and diesel fuel which could result in lower prices and
reduce operating margins.
Increases in required fuel economy and regulation of CO2 emissions from motor vehicles may reduce demand for transportation
fuels.
In 2010, the EPA and the National Highway Traffic Safety Administration (“NHTSA”) finalized new standards, raising the required
Corporate Average Fuel Economy (“CAFE”) of the nation's passenger fleet by 40% to approximately 35 miles per gallon (“m.p.g.”)
by 2016 and imposing the first-ever federal GHG emissions standards on cars and light trucks. In September 2011, the EPA and
the Department of Transportation finalized first-time standards for fuel economy of medium and heavy duty trucks. On August
28, 2012 the EPA and NHTSA adopted standards through model year 2025 in two phases. The first phase establishes final standards
for 2017-2021 model year vehicles that are projected to require 40.3 - 41.0 m.p.g. in model year 2021 on an average industry fleet-
wide basis. The second phase of the CAFE program represents non-final “augural” standards for 2022-2025 model year vehicles
that are projected to require 48.7 - 49.7 m.p.g. in model year 2025, on an average industry fleet-wide basis. Such increases in fuel
economy standards, along with mandated increases in use of renewable fuels discussed above, could result in decreasing demand
for petroleum fuels. Decreasing demand for petroleum fuels could have a material effect on our financial condition and results of
operation.
We may be unable to pay future regular and/or special dividends.
We will only be able to pay dividends from our available cash on hand, cash from operations or borrowings under our credit
agreement. The declaration of future regular and/or special dividends on our common stock will be at the discretion of our board
of directors and will depend upon many factors, including our results of operations, financial condition, earnings, capital
requirements, and restrictions in our debt agreements and legal requirements. We cannot assure you that any dividends will be
paid or the frequency of such payments.
Product liability claims and litigation could adversely affect our business and results of operations.
A significant portion of our operating responsibility on refined product pipelines is to insure the quality and purity of the products
loaded at our loading racks. If our quality control measures were to fail, we may have contaminated or off-specification commingled
pipelines and storage tanks or off-specification product could be sent to public gasoline stations. These types of incidents could
result in product liability claims from our customers.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against
manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no
assurance that product liability claims against us would not have a material adverse effect on our business or results of operations
or our ability to maintain existing customers or retain new customers.
Our hedging transactions may limit our gains and expose us to other risks.
We periodically enter into derivative transactions as it relates to inventory levels and/or future production to manage the risks from
changes in the prices of crude oil, refined products and other feedstocks. These transactions limit our potential gains if commodity
prices move above or below the certain price levels established by our hedging instruments. We hedge price risk on inventories
above our target levels to minimize the impact these price fluctuations have on our earnings and cash flows. Consequently, our
hedging results may fluctuate significantly from one reporting period to the next depending on commodity price fluctuations and
our relative physical inventory positions. These transactions may also expose us to risks of financial losses; for example, if our
production is less than we anticipated at the time we entered into a hedge agreement or if a counterparty to our hedge agreements
fails to perform its obligations under the agreements.
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Changes in our credit profile, or a significant increase in the price of crude oil, may affect our relationship with our suppliers,
which could have a material adverse effect on our liquidity and limit our ability to purchase sufficient quantities of crude oil
to operate our refineries at desired capacity.
An unfavorable credit profile, or a significant increase in the price of crude oil, could affect the way crude oil suppliers view our
ability to make payments and induce them to shorten the payment terms of their invoices with us or require credit enhancement.
Due to the large dollar amounts and volume of our crude oil and other feedstock purchases, any imposition by our suppliers of
more burdensome payment terms or credit enhancement requirements on us may have a material adverse effect on our liquidity
and our ability to make payments to our suppliers. This in turn could cause us to be unable to operate our refineries at desired
capacity. A failure to operate our refineries at desired capacity could adversely affect our profitability and cash flow.
Our debt agreements contain operating and financial restrictions that might constrain our business and financing activities.
The operating and financial restrictions and covenants in our credit facilities and any future financing agreements could adversely
affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example,
our revolving credit facility imposes usual and customary requirements for this type of credit facility, including: (i) maintenance
of certain levels of the fixed charge coverage ratio; (ii) limitations on liens, investments, indebtedness and dividends; (iii) a
prohibition on changes in control and (iv) restrictions on engaging in mergers, consolidations and sales of assets, entering into
certain lease obligations, and making certain investments or capital expenditures. If we fail to satisfy the covenants set forth in
the credit facility or another event of default occurs under the facility, the maturity of the loan could be accelerated or we could
be prohibited from borrowing for our future working capital needs and issuing letters of credit. We might not have, or be able to
obtain, sufficient funds to make these immediate payments. Should we desire to undertake a transaction that is prohibited by the
covenants in our credit facilities, we will need to obtain consent under our credit facilities. Such refinancing may not be possible
or may not be available on commercially acceptable terms. In addition, our obligations under our credit facilities are secured by
inventory, receivables and pledged cash assets. If we are unable to repay our indebtedness under our credit facilities when due,
the lenders could seek to foreclose on the assets or we may be required to contribute additional capital to our subsidiaries. Any of
these outcomes could have a material adverse effect on our business, financial condition and results of operations.
Our business may suffer due to a change in the composition of our Board of Directors, or if any of our key senior executives
or other key employees discontinue employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor
force may make it difficult for us to maintain labor productivity.
Our future performance depends to a significant degree upon the continued contributions of our senior management team and key
technical personnel. We do not currently maintain key man life insurance, non-compete agreements, or employment agreements
with respect to any member of our senior management team. The loss or unavailability to us of any member of our senior management
team or a key technical employee could significantly harm us. We face competition for these professionals from our competitors,
our customers and other companies operating in our industry. To the extent that the services of members of our senior management
team and key technical personnel would be unavailable to us for any reason, we may be required to hire other personnel to manage
and operate our company. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all.
Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks. A shortage of trained
workers due to retirements or otherwise could have an adverse impact on our labor productivity and costs and our ability to expand
production in the event there is an increase in the demand for our products and services, which could adversely affect our operations.
As of December 31, 2012, approximately 34% of our employees were represented by labor unions under collective bargaining
agreements with various expiration dates. We may not be able to renegotiate our collective bargaining agreements when they
expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not
prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results
of operations and financial condition.
Item 1B. Unresolved Staff Comments
We do not have any unresolved staff comments.
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Item 3. Legal Proceedings
Commitment and Contingency Reserves
We periodically establish reserves for certain legal proceedings. The establishment of a reserve involves an estimation process
that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to
be adequate, future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of
loss and amounts accrued.
While the outcome and impact on us cannot be predicted with certainty, management believes that the resolution of these proceedings
through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow.
Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.
Propane Pit - Woods Cross
In December 2011, the EPA conducted an inspection at Woods Cross and identified some alleged violations of the Chemical
Accident Prevention and Risk Management Plan (“RMP”) requirements set forth in section 112(r)(7) of the Federal Clean Air Act
and Part 68 of Title 40 of the Code of Federal Regulations. Following extended negotiations, Holly Refining & Marketing – Woods
Cross LLC and the EPA on October 12, 2012 agreed to resolve this matter with a civil penalty of $115,000, subject to the parties'
agreement on the final terms of two documents – an Administrative Compliance Order on Consent (“ACOC”) specifying the
details of the closure of the Frozen Earth Propane Storage Pit and a Combined Complaint and Consent Agreement (“CCCA”)
detailing the EPA allegations and resolution of those allegations. Neither of these agreements require Holly Refining & Marketing
– Woods Cross LLC to admit or deny the EPA's allegations. As of December 14, 2012, the ACOC and CCCA were signed by all
required parties and are now final.
Additional Environmental Matters
We are reporting the following proceedings to comply with SEC regulations which require us to disclose proceedings arising under
federal, state or local provisions regulating the discharge of materials into the environment or protecting the environment if we
reasonably believe that such proceedings may result in monetary sanctions of $100,000 or more. Our respective subsidiaries have
or will develop corrective action plans regarding these disclosures that will be implemented in consultation with the respective
federal and state agencies. It is not possible to predict the ultimate outcome of these proceedings, although none are currently
expected to have a material effect on our consolidated financial position.
Frontier Refining LLC (“FR”), our wholly-owned subsidiary, has undertaken environmental audits at the Cheyenne Refinery
regarding compliance with federal and state air quality and waste requirements. By letters dated October 5, 2012, and November
7, 2012, FR submitted reports to the EPA voluntarily disclosing non-compliance with certain emission limitations, reporting, and
other provisions of a 2009 federal consent decree. By letter dated January 10, 2013, FR submitted to the EPA a voluntary self-
disclosure of preliminary audit findings consistent with the EPA’s Audit Policy. By letter dated October 31, 2012, FR submitted
a preliminary report to the Wyoming Department of Environmental Quality (“WDEQ”) voluntarily disclosing non-compliance
with certain notification, reporting, and other provisions of the refinery's state air permits and other regulatory requirements. The
Cheyenne Refinery also has four outstanding Notices of Violations issued in 2010, 2011 and 2013 that are subject to ongoing
settlement negotiations with the WDEQ. Additional air, water and waste audits are ongoing or planned for the Cheyenne Refinery
for 2013.
Ethanol Management Company LLC (“EMC”), our wholly-owned subsidiary, has undertaken an environmental audit at the terminal
located in Henderson, Colorado regarding compliance with the hazardous waste requirements administered by the Colorado
Department of Public Health and Environment (“CDPHE”). By letter dated November 7, 2012, EMC notified the CDPHE of non-
compliance under hazardous waste regulations associated with waste water storage, and on February 4, 2013, the CDPHE notified
EMC that this matter is formally closed and no action will be taken in response to the self-disclosure.
Between November 2010 and February 2012, certain of our subsidiaries submitted multiple reports to the EPA to voluntarily
disclose non-compliance with fuels regulations at the Cheyenne, El Dorado, Navajo, Tulsa and Woods Cross refineries and at the
Cedar City, Utah and Henderson, Colorado terminals. The EPA has requested additional information regarding certain of these
reports, and our subsidiaries have complied with all requests received to date.
Other
We are a party to various other litigation and proceedings that we believe, based on advice of counsel, will not either individually
or in the aggregate have a materially adverse impact on our financial condition, results of operations or cash flows.
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Item 4. Mine Safety Disclosures
Not Applicable.
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PART II
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Our common stock is traded on the New York Stock Exchange under the trading symbol “HFC.” The following table sets forth
the range of the daily high and low sales prices per share of common stock, dividends declared per share and the trading volume
of common stock for the periods indicated:
Years Ended December 31,
High
Low
Dividends
Trading Volume
2012
Fourth quarter
Third quarter
Second quarter
First quarter
2011
Fourth quarter
Third quarter
Second quarter
First quarter
$
$
$
$
$
$
$
$
47.39
42.33
36.10
36.45
35.00
38.90
34.94
31.61
$
$
$
$
$
$
$
$
36.22
33.92
28.05
23.96
21.13
24.25
25.30
19.92
$
$
$
$
$
$
$
$
0.700
1.150
0.650
0.600
0.600
0.588
0.075
0.075
161,950,900
171,023,300
232,551,400
230,380,300
243,985,000
261,573,400
212,391,800
149,825,800
In January 2012, our Board of Directors approved a $350 million stock repurchase program, and in June 2012, approved an
additional $350 million repurchase program that authorizes us to repurchase common stock in the open market or through privately
negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and
other relevant considerations. These programs may be discontinued at any time by the Board of Directors. The following table
includes repurchases made under these programs during the fourth quarter of 2012.
Period
October 2012
November 2012
December 2012 (1)
Total for October to December 2012
Total Number of
Shares Purchased
398,131
26,100
134,200
558,431
Average Price
Paid Per Share
37.27
$
37.95
$
45.67
$
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs
Maximum Dollar
Value of Shares
that May Yet Be
Purchased under the
Plans or Programs
398,131
26,100
$
$
— $
424,231
495,390,494
494,399,956
494,399,956
(1) The December 2012 shares repurchased were not purchased under our approved stock repurchase program, but rather pursuant to separate
authority from our Board of Directors. These repurchases were made in the open market.
As of February 13, 2013, we had approximately 88,000 stockholders, including beneficial owners holding shares in street name.
We intend to consider the declaration of a dividend on a quarterly basis, although there is no assurance as to future dividends since
they are dependent upon future earnings, capital requirements, our financial condition and other factors. Our credit agreement and
senior notes limit the payment of dividends. See Note 13 “Debt” in the Notes to Consolidated Financial Statements.
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Item 6. Selected Financial Data
The following table shows our selected financial information as of the dates or for the periods indicated. This table should be read
in conjunction with Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations” and our
consolidated financial statements and related notes thereto included elsewhere in this Annual Report on Form 10-K.
2012
Years Ended December 31,
2010
2009
2011
2008
FINANCIAL DATA (1)
For the period
Sales and other revenues
Income from continuing operations before income taxes
Income tax provision
Income from continuing operations
Income from discontinued operations, net of taxes (2)
Net income
Less net income attributable to noncontrolling interest
Net income attributable to HollyFrontier stockholders
Earnings per share attributable to HollyFrontier
stockholders - basic
Earnings per share attributable to HollyFrontier
stockholders - diluted
Cash dividends declared per common share
Average number of common shares outstanding:
(In thousands, except per share date)
$ 20,090,724
2,787,995
1,027,962
1,760,033
—
1,760,033
32,861
$ 1,727,172
$ 15,439,528
1,641,695
581,991
1,059,704
—
1,059,704
36,307
$ 1,023,397
$ 8,322,929
192,363
59,312
133,051
—
133,051
29,087
103,964
$
$ 4,834,268
43,803
7,460
36,343
16,926
53,269
33,736
19,533
$
$ 5,860,357
187,746
64,028
123,718
2,918
126,636
6,078
120,558
$
$
$
$
8.41
8.38
3.10
$
$
$
6.46
6.42
1.34
$
$
$
0.98
0.97
0.30
$
$
$
0.20
0.20
0.30
$
$
$
1.20
1.19
0.30
Basic
Diluted
205,289
206,184
158,486
159,294
106,436
107,218
100,836
101,206
100,404
101,098
Net cash provided by operating activities
Net cash provided by (used for) investing activities
Net cash provided by (used for) financing activities
At end of period
Cash, cash equivalents and investments in marketable
securities
Working capital
Total assets (3)
Total debt (4)
Total equity
$ 1,662,687
$
$
(711,104) $
(772,788) $
$
$ 1,338,391
228,494
$
(217,082) $
283,255
$
(213,232) $
$
34,482
211,545
$
(534,603) $
$
406,849
155,490
(57,777)
(151,277)
$ 2,393,401
$ 2,815,821
$ 10,328,997
$ 1,336,238
$ 6,642,658
$ 1,840,610
$ 2,030,063
$ 9,576,243
$ 1,214,742
$ 5,835,900
230,444
$
$
313,580
$ 3,049,951
$
810,561
$ 1,288,139
125,819
$
$
257,899
$ 2,766,318
$
707,458
$ 1,207,781
94,447
$
$
68,465
$ 1,728,293
370,914
$
936,332
$
(1) We merged with Frontier on July 1, 2011. Our consolidated financial and operating results reflect the operations of the merged Frontier
businesses beginning July 1, 2011. See “Company Overview” under Items 1 and 2, “Business and Properties” for information on our
merger.
(2) On December 1, 2009, HEP sold its 70% interest in Rio Grande. Results of operations of Rio Grande are presented in discontinued
operations.
(3) Prior period total assets have been recast to reflect a net amount due under contractual netting agreements. See Note 2 “Change in
Accounting Principle” in the Notes to Consolidated Financial Statements.
(4) Includes total HEP debt of $864.7 million, $525.9 million, $482.3 million, $379.2 million and $370.9 million, respectively, which is
non-recourse to HollyFrontier.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Item 7 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of this Annual Report
on Form 10-K. In this document, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and its consolidated subsidiaries
or to HollyFrontier or an individual subsidiary and not to any other person with certain exceptions. Generally, the words “we,”
“our,” “ours” and “us” include HEP and its subsidiaries as consolidated subsidiaries of HollyFrontier, unless when used in
disclosures of transactions or obligations between HEP and HollyFrontier or its other subsidiaries. This document contains certain
disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations
of HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.
We merged with Frontier on July 1, 2011. Accordingly, this document includes Frontier, its consolidated subsidiaries and the
operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date.
Overview
We are principally an independent petroleum refiner that produces high-value refined products such as gasoline, diesel fuel, jet
fuel, specialty lubricant products, and specialty and modified asphalt. We own and operate refineries having a combined crude oil
processing capacity of 443,000 barrels per day that serve markets throughout the Mid-Continent, Southwest and Rocky Mountain
regions of the United States. Our refineries are located in El Dorado, Kansas (the El Dorado Refinery), Tulsa, Oklahoma (the Tulsa
Refineries), which comprise two production facilities, the Tulsa West and East facilities, a petroleum refinery in Artesia, New
Mexico, which operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington,
New Mexico (the Navajo Refinery), Cheyenne, Wyoming (the Cheyenne Refinery) and Woods Cross, Utah (the Woods Cross
Refinery).
Our discussion of financial and operating results for the years ended December 31, 2012, 2011 and 2010 is presented in the
following section.
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Results Of Operations
Financial Data
2012
Years Ended December 31,
2011 (1)
(In thousands, except per share data)
2010
Sales and other revenues
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization)
Operating expenses (exclusive of depreciation and amortization)
General and administrative expenses (exclusive of depreciation
and amortization)
Depreciation and amortization
Total operating costs and expenses
Income from operations
Other income (expense):
Earnings of equity method investments
Interest income
Interest expense
Gain on sale of marketable securities
Merger transaction costs
Income before income taxes
Income tax provision
Net income
Less net income attributable to noncontrolling interest
Net income attributable to HollyFrontier stockholders
Earnings per share attributable to HollyFrontier stockholders:
Basic
Diluted
Cash dividends declared per common share
Average number of common shares outstanding:
Basic
Diluted
$
20,090,724
$
15,439,528
$
8,322,929
15,840,643
994,966
128,101
242,868
17,206,578
2,884,146
2,923
4,786
(104,186)
326
—
(96,151)
2,787,995
1,027,962
1,760,033
32,861
1,727,172
8.41
8.38
3.10
$
$
$
$
12,680,078
748,081
120,114
159,707
13,707,980
1,731,548
2,300
1,284
(78,323)
—
(15,114)
(89,853)
1,641,695
581,991
1,059,704
36,307
1,023,397
6.46
6.42
1.34
$
$
$
$
$
$
$
$
7,367,149
504,414
70,839
117,529
8,059,931
262,998
2,393
1,168
(74,196)
—
—
(70,635)
192,363
59,312
133,051
29,087
103,964
0.98
0.97
0.30
205,289
206,184
158,486
159,294
106,436
107,218
(1) Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011. Assuming
the merger had been consummated on January 1, 2010, pro forma revenues and net income for the years ended December 31, 2011 and
2010 are as follows:
Years Ended December 31,
2011
2010
(In thousands)
Sales and other revenues
Net income attributable to HollyFrontier stockholders
$
$
19,418,709
1,335,257
$
$
14,207,835
179,979
Other Financial Data
Net cash provided by operating activities
Net cash provided by (used for) investing activities
Net cash provided by (used for) financing activities
Capital expenditures
EBITDA (1)
2012
Years Ended December 31,
2011
(In thousands)
2010
$
$
$
$
$
1,662,687
$
(711,104) $
(772,788) $
$
335,263
$
3,097,402
$
1,338,391
228,494
$
(217,082) $
$
374,241
$
1,842,134
283,255
(213,232)
34,482
213,232
353,833
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(1) Earnings before interest, taxes, depreciation and amortization, which we refer to as “EBITDA,” is calculated as net income
plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA
is not a calculation provided for under GAAP; however, the amounts included in the EBITDA calculation are derived from
amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income
or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure
of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented
here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also
used by our management for internal analysis and as a basis for financial covenants. EBITDA presented above is reconciled
to net income under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following
Item 7A of Part II of this Form 10-K.
Our operations are organized into two reportable segments, Refining and HEP. See Note 21 “Segment Information” in the Notes
to Consolidated Financial Statements for additional information on our reportable segments.
Refining Operating Data
Our refinery operations include the El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries. The following tables set
forth information, including non-GAAP performance measures about our consolidated refinery operations. The cost of products
and refinery gross and net operating margins do not include the effect of depreciation and amortization. Reconciliations to amounts
reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles”
following Item 7A of Part II of this Form 10-K.
Consolidated
Crude charge (BPD) (1)
Refinery throughput (BPD) (2)
Refinery production (BPD) (3)
Sales of produced refined products (BPD)
Sales of refined products (BPD) (4)
Refinery utilization (5)
Average per produced barrel (6)
Net sales
Cost of products (7)
Refinery gross margin
Refinery operating expenses (8)
Net operating margin
Refinery operating expenses per throughput barrel (9)
Years Ended December 31,
2011 (10)
2010
2012
415,210
453,740
442,730
431,060
443,620
315,000
340,200
331,890
332,720
340,630
221,440
234,910
225,980
228,140
232,100
93.7%
89.9%
86.5%
$
$
$
119.48
94.59
24.89
5.49
19.40
5.22
$
$
$
118.82
98.18
20.64
5.36
15.28
5.24
$
$
$
91.06
82.27
8.79
5.08
3.71
4.94
(1) Crude charge represents the barrels per day of crude oil processed at our refineries.
(2) Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion
units at our refineries.
(3) Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks
through the crude units and other conversion units at our refineries.
(4) Includes refined products purchased for resale.
(5) Represents crude charge divided by total crude capacity (BPSD). Effective July 1, 2011, our consolidated crude capacity increased
from 256,000 BPSD to 443,000 BPSD as a result of our merger with Frontier.
(6) Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts
reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles”
following Item 7A of Part II of this Form 10-K.
(7) Transportation, terminal and refinery storage costs billed from HEP are included in cost of products.
(8) Represents operating expenses of our refineries, exclusive of depreciation and amortization.
(9) Represents refinery operating expenses, exclusive of depreciation and amortization, divided by refinery throughput.
(10) Refining operating data for the year ended December 31, 2011 include crude oil processed and products yielded from the El Dorado
and Cheyenne Refineries for the period from July 1, 2011 through December 31, 2011 only, and averaged over the 365 days in the
year ended December 31, 2011.
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Results of Operations – Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Summary
Net income attributable to HollyFrontier stockholders for the year ended December 31, 2012 was $1,727.2 million ($8.41 per
basic and $8.38 per diluted share), a $703.8 million increase compared to $1,023.4 million ($6.46 per basic and $6.42 per diluted
share) for the year ended December 31, 2011. Net income increased due principally to greater operating scale following our July
1, 2011 merger and higher refining margins in the current year. Refinery gross margins for the year ended December 31, 2012
increased to $24.89 per produced barrel compared to $20.64 for the year ended December 31, 2011.
Sales and Other Revenues
Sales and other revenues increased 30% from $15,439.5 million for the year ended December 31, 2011 to $20,090.7 million for
the year ended December 31, 2012, due principally to the inclusion of sales volumes and related revenues attributable to the El
Dorado and Cheyenne Refineries for a full year period and higher sales volumes of refined products produced from the legacy
Holly refineries. Additionally, the average sales price we received per produced barrel sold increased 1% from $118.82 for the
year ended December 31, 2011 to $119.48 for the year ended December 31, 2012. Sales and other revenues for the years ended
December 31, 2012 and 2011 include $47.6 million and $46.4 million, respectively, in HEP revenues attributable to pipeline and
transportation services provided to unaffiliated parties.
Cost of Products Sold
Cost of products sold increased 25% from $12,680.1 million for the year ended December 31, 2011 to $15,840.6 million for the
year ended December 31, 2012, due principally to the inclusion of sales volumes and related cost of products sold at the El Dorado
and Cheyenne Refineries, partially offset by lower crude oil costs for the current year. The average price we paid per barrel for
crude oil and feedstocks and the transportation costs of moving the finished products to the market place decreased 4% from
$98.18 for the year ended December 31, 2011 to $94.59 for the year ended December 31, 2012.
Gross Refinery Margins
Gross refinery margin per produced barrel increased 21% from $20.64 for the year ended December 31, 2011 to $24.89 for the
year ended December 31, 2012. This is due to the effects of a current year decrease in crude oil and feedstock prices along with
slightly higher sales prices received on produced products sold. Gross refinery margin does not include the effects of depreciation
and amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A
of Part II of this Form 10-K for a reconciliation to the income statement of prices of refined products sold and cost of products
purchased.
Operating Expenses
Operating expenses, exclusive of depreciation and amortization, increased 33% from $748.1 million for the year ended
December 31, 2011 to $995.0 million for the year ended December 31, 2012, due principally to the inclusion of the legacy Frontier
refinery operations for a full-year period and higher repair and maintenance and environmental remediation costs. For the current
year, we increased certain environmental remediation accruals by $46.1 million to reflect revisions to certain cost estimates and
the timeframe for which certain environmental remediation and monitoring activities are expected to occur. Also contributing to
a much lesser extent were increased payroll costs attributable to the legacy Holly refining operations. For the years ended
December 31, 2012 and 2011, operating expenses include $88.9 million and $61.1 million, respectively, in costs attributable to
HEP operations.
General and Administrative Expenses
General and administrative expenses increased 7% from $120.1 million for the year ended December 31, 2011 to $128.1 million
for the year ended December 31, 2012, due principally to higher employee benefit and equity-based compensation costs and
increased corporate staffing levels as a result of our July 1, 2011 merger, net of the effects of merger related severance and integration
costs incurred during 2011. For the years ended December 31, 2012 and 2011, general and administrative expenses include $5.3
million and $4.3 million, respectively, in costs attributable to HEP operations.
Depreciation and Amortization Expenses
Depreciation and amortization increased 52% from $159.7 million for the year ended December 31, 2011 to $242.9 million for
the year ended December 31, 2012. The increase was due principally to depreciation and amortization attributable to the legacy
Frontier refinery assets, capitalized improvement projects and HEP's UNEV Pipeline. For the years ended December 31, 2012
and 2011, depreciation and amortization expenses include $57.8 million and $33.3 million, respectively, in costs attributable to
HEP operations.
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Interest Income
Interest income for the year ended December 31, 2012 was $4.8 million compared to $1.3 million for the year ended December 31,
2011. This increase was due to interest received on our increased cash position and investments in marketable debt securities.
Interest Expense
Interest expense was $104.2 million for the year ended December 31, 2012 compared to $78.3 million for the year ended
December 31, 2011. This increase principally reflects interest on the senior notes assumed upon our merger with Frontier. For the
years ended December 31, 2012 and 2011, interest expense included $57.2 million and $38.2 million, respectively, in interest costs
attributable to HEP operations.
Merger Transaction Costs
For the year ended December 31, 2011, we recognized merger transaction costs of $15.1 million related to our merger with Frontier
on July 1, 2011. These costs included legal, advisory and other professional fees that were directly attributable to the merger. There
were no such costs incurred for the year ended December 31, 2012.
Income Taxes
For the year ended December 31, 2012, we recorded income tax expense of $1,028.0 million compared to $582.0 million for the
year ended December 31, 2011. This increase is due principally to significantly higher pre-tax earnings during the year ended
December 31, 2012 compared to the same period of 2011. Our effective tax rates, before consideration of earnings attributable to
the noncontrolling interest, were 36.9% and 35.5% for the years ended December 31, 2012 and 2011, respectively. Our effective
tax rate for GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest holders
in the denominator of our effective tax rate computation.
Results of Operations – Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Summary
Net income attributable to HollyFrontier Corporation stockholders for the year ended December 31, 2011 was $1,023.4 million
($6.46 per basic and $6.42 per diluted share) a $919.4 million increase compared to $104.0 million ($0.98 per basic and $0.97 per
diluted share) for the year ended December 31, 2010. Net income increased due principally to earnings attributable to the merged
Frontier business operations which are included in our results beginning July 1, 2011, and due to significantly higher refinery
gross margins during 2011. Overall refinery gross margins for the year ended December 31, 2011 were $20.64 per produced barrel
compared to $8.79 for the year ended December 31, 2010.
Overall production levels for the year ended December 31, 2011 increased by 47% over 2010 due to the inclusion of the El Dorado
and Cheyenne Refinery operations following our merger with Frontier beginning July 1, 2011.
Sales and Other Revenues
Sales and other revenues increased 86% from $8,322.9 million for the year ended December 31, 2010 to $15,439.5 million for
the year ended December 31, 2011, due principally to the inclusion of $4,183.8 million in revenues attributable to the El Dorado
and Cheyenne Refinery operations and the effects of increased refined product sales prices over 2010. The average sales price we
received per produced barrel sold increased 30% from $91.06 for the year ended December 31, 2010 to $118.82 for the year ended
December 31, 2011. Sales and other revenues for the years ended December 31, 2011 and 2010, include $46.4 million and $36.0
million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.
Cost of Products Sold
Cost of products sold increased 72% from $7,367.1 million for the year ended December 31, 2010 to $12,680.1 million for the
year ended December 31, 2011, due principally to the inclusion of results from the El Dorado and Cheyenne Refinery operations,
and higher crude oil costs. The average price we paid per barrel of crude oil and feedstocks used in production and the transportation
costs of moving the finished products to the market place increased 19% from $82.27 for the year ended December 31, 2010 to
$98.18 for the year ended December 31, 2011.
Gross Refinery Margins
Gross refining margin per produced barrel increased 135% from $8.79 for the year ended December 31, 2010 to $20.64 for the
year ended December 31, 2011, due to an increase in the average sales price we received per produced barrel sold, partially offset
by an increase in the average price we paid per produced barrel of crude oil and feedstocks. Gross refining margin does not include
the effects of depreciation or amortization.
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Operating Expenses
Operating expenses, exclusive of depreciation and amortization increased 48% from $504.4 million for the year ended
December 31, 2010 to $748.1 million for the year ended December 31, 2011, due principally to costs attributable to the El Dorado
and Cheyenne Refinery operations. Also contributing to a much lesser extent were increased payroll and maintenance costs
attributable to the legacy Holly refining operations. For the years ended December 31, 2011 and 2010, operating expenses include
$61.1 million and $52.7 million, respectively, in costs attributable to HEP operations.
General and Administrative Expenses
General and administrative expenses increased 70% from $70.8 million for the year ended December 31, 2010 to $120.1 million
for the year ended December 31, 2011. This includes $26.5 million in integration and severance costs associated with the merger
integration. It also reflects higher payroll, equity based compensation costs and support costs for our larger organization. For the
years ended December 31, 2011 and 2010, general and administrative expenses include $4.3 million and $5.4 million, respectively,
in costs attributable to HEP operations.
Depreciation and Amortization Expenses
Depreciation and amortization increased 36% from $117.5 million for the year ended December 31, 2010 to $159.7 million for
the year ended December 31, 2011. The increase was due principally to depreciation and amortization attributable to the El Dorado
and Cheyenne Refinery operations and capitalized improvement projects. For the years ended December 31, 2011 and 2010,
depreciation and amortization expenses include $33.3 million and $28.9 million, respectively, in costs attributable to HEP
operations.
Interest Income
Interest income for the year ended December 31, 2011 was $1.3 million compared to $1.2 million for the year ended December 31,
2010. For the year ended December 31, 2011, interest income reflects higher cash investment levels in 2011. Additionally, interest
income for the year ended December 31, 2010 reflects interest received on income tax refunds.
Interest Expense
Interest expense was $78.3 million for the year ended December 31, 2011 compared to $74.2 million for the year ended
December 31, 2010. This increase reflects the write-off of $5.0 million of previously deferred financing costs due to the July 1,
2011 termination of our previous credit agreement and the inclusion of interest attributable to the senior notes assumed upon our
merger with Frontier. Additionally, during 2011 we capitalized $17.2 million in interest attributable to construction projects. For
the years ended December 31, 2011 and 2010, interest expense included $38.2 million and $36.2 million, respectively, in costs
attributable to HEP operations.
Merger Transaction Costs
For the year ended December 31, 2011, we recognized merger transaction costs of $15.1 million related to our merger with Frontier
on July 1, 2011. These costs relate to legal, advisory and other professional fees that are directly attributable to the merger.
Income Taxes
Income taxes increased from $59.3 million for the year ended December 31, 2010 to $582.0 million for the year ended December 31,
2011 due to significantly higher pre-tax earnings for the year ended December 31, 2011 compared to 2010. Our effective tax rate,
before consideration of earnings attributable to noncontrolling interests was 35.5% for the year ended December 31, 2011 compared
to 30.8% for the year ended December 31, 2010. Our effective tax rate for GAAP disclosure purposes reflects the inclusion of
non-taxable earnings attributable to noncontrolling interest holders in the denominator of our effective tax rate computation.
LIQUIDITY AND CAPITAL RESOURCES
HollyFrontier Credit Agreement
We have a $1 billion senior secured credit agreement (the “HollyFrontier Credit Agreement”) with Union Bank, N.A. as
administrative agent and certain lenders from time to time party thereto. The HollyFrontier Credit Agreement matures in July 2016
and may be used to fund working capital requirements, capital expenditures, acquisitions and general corporate purposes.
Obligations under the HollyFrontier Credit Agreement are collateralized by our inventory, accounts receivables and certain deposit
accounts and guaranteed by our material, wholly-owned subsidiaries. At December 31, 2012, we were in compliance with all
covenants, had no outstanding borrowings and had outstanding letters of credit totaling $29.2 million under the HollyFrontier
Credit Agreement.
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HEP Credit Agreement
HEP has a $550 million senior secured revolving credit facility that matures in June 2017 (the “HEP Credit Agreement”) and is
available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general
partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders
up to a $60 million sub-limit. At December 31, 2012, HEP was in compliance with all of its covenants, had outstanding borrowings
of $421.0 million and no outstanding letters of credit under the HEP Credit Agreement.
HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically
in our consolidated balance sheets). Indebtedness under the HEP Credit Agreement involves recourse to HEP Logistics Holdings,
L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be
limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s
creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated
subsidiaries.
HollyFrontier Senior Notes
Our senior notes consist of the following:
•
•
9.875% senior notes ($286.8 million principal amount maturing June 2017)
6.875% senior notes ($150 million principal amount maturing November 2018)
These senior notes (collectively the “HollyFrontier Senior Notes”) are unsecured and impose certain restrictive covenants, including
limitations on our ability to incur additional debt, incur liens, enter into sale-and-leaseback transactions, pay dividends, enter into
mergers, sell assets and enter into certain transactions with affiliates. At any time when the HollyFrontier Senior Notes are rated
investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many
of the foregoing covenants. Additionally, we have certain redemption rights under the HollyFrontier Senior Notes.
In September 2012, we redeemed our $200 million aggregate principal amount of 8.5% senior notes maturing September 2016 at
a redemption price of $208.5 million.
HollyFrontier Financing Obligation
We have a financing obligation that relates to a sale and lease-back of certain crude oil tankage that we sold to an affiliate of Plains
All American Pipeline, L.P. (“Plains”) in October 2009 for $40.0 million. Monthly lease payments are recorded as a reduction in
principal over the 15-year lease term ending in 2024.
HEP Senior Notes
HEP’s senior notes consist of the following:
•
•
8.25% HEP senior notes ($150 million principal amount maturing March 2018)
6.5% HEP senior notes ($300 million principal amount maturing March 2020)
In March 2012, HEP issued $300 million in an aggregate principal amount of 6.5% HEP senior notes maturing March 2020. The
$294.8 million in net proceeds were used to repay $157.8 million aggregate principal amount of 6.25% HEP senior notes, $72.9
million in promissory notes due to HollyFrontier, related fees, expenses and accrued interest in connection with these transactions
and to repay borrowings under the HEP Credit Agreement. In April 2012, HEP called for redemption the remaining $27.2 million
aggregate principal amount outstanding of 6.25% HEP senior notes.
The 8.25% and 6.5% HEP senior notes (collectively, the “HEP Senior Notes”) are unsecured and impose certain restrictive
covenants, including limitations on HEP’s 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 HEP Senior Notes are
rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject
to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes.
Indebtedness under the HEP Senior Notes involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed
by HEP’s wholly-owned subsidiaries. However, any recourse to the general partner would be limited to the extent of HEP Logistics
Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no other recourse to our
assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.
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Liquidity
We believe our current cash and cash equivalents, along with future internally generated cash flow and funds available under our
credit facilities will provide sufficient resources to fund currently planned capital projects and our liquidity needs for the foreseeable
future. In addition, components of our growth strategy include construction of new refinery processing units and the expansion
of existing units at our facilities and selective acquisition of complementary assets for our refining operations intended to increase
earnings and cash flow.
As of December 31, 2012, our cash, cash equivalents and investments in marketable securities totaled $2.4 billion. We consider
all highly-liquid instruments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents
are stated at cost, which approximates market value, and are invested primarily in conservative, highly-rated instruments issued
by financial institutions or government entities with strong credit standings.
In January 2012, our Board of Directors approved a $350 million stock repurchase program, and in June 2012, approved an
additional $350 million repurchase program that authorizes us to repurchase common stock in the open market or through privately
negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and
other relevant considerations. These programs may be discontinued at any time by the Board of Directors. As of December 31,
2012, we have repurchased 6,775,729 shares at a cost of $205.6 million, with remaining authorization to repurchase $494.4 million
under these stock repurchase programs.
Cash and cash equivalents increased $178.8 million for the year ended December 31, 2012. Cash provided by operating activities
of $1,662.7 million exceeded net cash used for investing and financing activities of $711.1 million and $772.8 million, respectively.
Working capital increased by $785.8 million during the year ended December 31, 2012.
Cash Flows – Operating Activities
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Net cash flows provided by operating activities were $1,662.7 million for the year ended December 31, 2012 compared to $1,338.4
million for the year ended December 31, 2011, an increase of $324.3 million. Net income for the year ended December 31, 2012
was $1,760.0 million, an increase of $700.3 million compared to $1,059.7 million for the year ended December 31, 2011. Non-
cash adjustments consisting of depreciation and amortization, gain on sale of equity securities, deferred income taxes, equity-
based compensation expense and fair value changes to derivative instruments resulted in an increase to operating cash flows of
$429.5 million for the year ended December 31, 2012 compared to $178.0 million for the same period in 2011. Changes in working
capital items decreased cash flows by $398.0 million for the year ended December 31, 2012 compared to an increase of $147.3
million for the year ended December 31, 2011. The decrease in working capital items for the year ended December 31, 2012 was
due principally to higher inventory levels and a decrease in income taxes payable and accrued liabilities due to timing differences
of payments during the fourth quarter of 2012 relative to 2011. Additionally, for the year ended December 31, 2012, turnaround
expenditures increased to $159.7 million from $32.0 million for the same period of 2011.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Net cash flows provided by operating activities were $1,338.4 million for the year ended December 31, 2011 compared to $283.3
million for the year ended December 31, 2010, an increase of $1,055.1 million. Net income for the year ended December 31, 2011
was $1,059.7 million, an increase of $926.6 million from $133.1 million for the year ended December 31, 2010. Non-cash
adjustments consisting of depreciation and amortization, deferred income taxes, equity-based compensation expense and derivative
instrument adjustments resulted in an increase to operating cash flows of $178.0 million for the year ended December 31, 2011
compared to $154.3 million for the year ended December 31, 2010. Changes in working capital items increased cash flows by
$147.3 million in 2011 compared to $24.7 million in 2010. The increase in working capital items for the year ended December
31, 2011 was due principally to the effects of higher levels of accrued liabilities at December 31, 2011 relative to 2010 as a result
of increased income taxes and costs supporting our recently merged company. Additionally, turnaround expenditures were $32.0
million and $35.0 million for the years ended December 31, 2011 and 2010, respectively.
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Cash Flows – Investing Activities and Planned Capital Expenditures
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Net cash flows used for investing activities were $711.1 million for the year ended December 31, 2012 compared to net cash flows
provided by investing activities of $228.5 million for the year ended December 31, 2011, a decrease of $939.6 million. Investing
activities for 2011 reflect a net cash inflow due to an $872.7 million increase in cash and cash equivalents as a result of our July
1, 2011 merger with Frontier. Cash expenditures for properties, plants and equipment for 2012 decreased to $335.3 million from
$374.2 million for the same period in 2011. These include HEP capital expenditures of $44.9 million and $216.2 million for the
years ended December 31, 2012 and 2011, respectively, which include 2011 capital expenditures of $164.3 million to construct
the UNEV Pipeline. Also for the years ended December 31, 2012 and 2011, we invested $671.6 million and $561.9 million,
respectively, in marketable securities and received proceeds of $297.7 million and $301.0 million, respectively, from the sale or
maturity of marketable securities.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Net cash flows provided by investing activities were $228.5 million for the year ended December 31, 2011 compared to net cash
flows used for investing activities $213.2 million for the year ended December 31, 2010, an increase of $441.7 million. Investing
activities for 2011 reflect a net cash inflow due to an $872.7 million increase in cash and cash equivalents as a result of our July
1, 2011 merger with Frontier. Cash expenditures for properties, plant and equipment for 2011 increased to $374.2 million compared
to $213.2 million for 2010. These include HEP capital expenditures of $216.2 million and $109.5 million for the years ended
December 31, 2011 and 2010, respectively. During the year ended December 31, 2011, we invested $9.1 million in Sabine Biofuels,
a development stage biodiesel production facility. Additionally for the year ended December 31, 2011, we invested $561.9 million
in marketable securities and received proceeds of $301.0 million from the sale of our marketable securities.
Planned Capital Expenditures
HollyFrontier Corporation
Each year our Board of Directors approves our annual capital budget which includes specific projects that our management is
authorized to undertake. Additionally, when conditions warrant or as new opportunities arise, additional projects may be
approved. The funds appropriated for a particular capital project may be expended over a period of several years, depending on
the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures
appropriated in that year’s capital budget plus expenditures for projects appropriated in prior years which have not yet been
completed. Our appropriated capital budget for 2013 is $320.0 million including both sustaining capital and major capital projects.
We expect to spend approximately $400.0 million to $450.0 million in cash for capital projects appropriated in 2013 plus those
appropriated in prior years but not yet completed. In addition, we expect to spend $156.0 million on refinery turnarounds and tank
maintenance. Refinery turnaround spending is amortized over the useful life of the turnaround while tank maintenance is expensed
as incurred. Our new capital appropriation for 2013 and expected cash spending is as follows:
New Appropriation
Expected Cash
Spending Range
(In millions)
Location:
El Dorado
Tulsa
Navajo
Cheyenne
Woods Cross
Corporate and Other
Total
Type:
Sustaining
Reliability and Growth
Compliance and Safety
Total
$
$
$
$
122.0
$
56.0 – $
68.0
22.0
52.0
41.0
15.0
116.0 –
28.0 –
58.0 –
130.0 –
12.0 –
65.0
130.0
33.0
61.0
146.0
15.0
320.0
$
400.0 – $
450.0
109.0
$
100.0 – $
177.0
34.0
196.0 –
104.0 –
320.0
$
400.0 – $
113.0
220.0
117.0
450.0
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A significant portion of our current capital spending is associated with compliance-oriented capital improvements. This spending
is required due to existing consent decrees (for projects including FCC unit flue gas scrubbers and tail gas treatment units), federal
fuels regulations (particularly, MSAT2 which mandates a reduction in the benzene content of blended gasoline), refinery waste
water treatment improvements and other similar initiatives. Our refinery operations and related emissions are highly regulated at
both federal and state levels, and we invest in our facilities as needed to remain in compliance with these standards. Additionally,
when faced with new emissions or fuels standards, we seek to execute projects that facilitate compliance and also improve the
operating costs and/or yields of associated refining processes.
El Dorado Refinery
Newly appropriated capital projects at the El Dorado Refinery include naphtha fractionation, an additional hydrogen plant and a
Low-Nox addition to the FCC unit flue gas scrubber. Continuing project work will include coke drum pressure reduction designed
to improve liquid yields and a new tail gas treatment unit to reduce air emissions in compliance with the El Dorado Refinery's
existing EPA consent decree.
Tulsa Refineries
New 2013 appropriations for the Tulsa Refineries include a gasoline-blending system and numerous infrastructure upgrades. We
will continue spending on the conversion of our propane de-asphalt unit to ROSE technology and on our sulfur recovery project
related to the refinery fuel gas system. This project will be completed in approximately the second quarter of 2013 and, in addition
to facilitating compliance with our EPA consent, will also allow us to increase use of lower priced sour / heavy crude in Tulsa.
Spending on maintenance capital items and general improvements continues at an elevated level at the Tulsa Refineries due to
perceived opportunities.
Navajo Refinery
The Navajo Refinery capital spending in 2013 will be principally on previously approved capital appropriations as well as
maintenance capital spending. Included among previously approved capital projects is a $25.0 million upgrade to the Navajo
Refinery's waste water treatment system.
Cheyenne Refinery
We plan to install a new hydrogen plant at the Cheyenne Refinery and have appropriated this capital project as part of our 2013
budget. The hydrogen plant, along with a previously approved naphtha fractionation project, will allow us to reduce benzene
content in Cheyenne gasoline production, while at the same time improving the refinery's overall liquid yields and light oils
production. Previously appropriated projects still underway at Cheyenne include wastewater treatment plant improvements, a wet
gas scrubber for the FCC unit to reduce air emissions, a redundant tail gas unit associated with sulfur recovery processes and
additional investment in the waste water treatment plant to reduce selenium concentration in waste water.
Woods Cross Refinery
Newly appropriated capital for the Woods Cross Refinery consists of warehouse and office relocations to accommodate the refinery
expansion and modernization program and of a new rail loading rack for intermediates and finished products associated with
refining waxy crude oil. We continue to work on the $225.0 million refinery expansion project announced previously, with expected
completion date in approximately the fourth quarter of 2014.
Regulatory compliance items or other presently existing or future environmental regulations / consent decrees could cause us to
make additional capital investments beyond those described above and incur additional operating costs to meet applicable
requirements.
HEP
Each year the Holly Logistic Services, L.L.C. board of directors approves HEP’s annual capital budget, which specifies capital
projects that HEP management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities
arise, special projects may be approved. The funds allocated for a particular capital project may be expended over a period of
several years, depending on the time required to complete the project. Therefore, HEP’s planned capital expenditures for a given
year consist of expenditures approved for capital projects included in its current year capital budget as well as, in certain cases,
expenditures approved for capital projects in capital budgets for prior years. The 2013 HEP capital budget is comprised of $9.2
million for maintenance capital expenditures and $2.3 million for expansion capital expenditures.
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HEP has recently made certain modifications to its crude oil gathering and trunk line system that have effectively increased HEP’s
ability to gather and transport an additional 10,000 BPD of Delaware Basin crude oil in response to increased drilling activity in
southeast New Mexico. HEP has a second project recently approved which consists of the reactivation and conversion to crude
oil service of a 70-mile, 8-inch petroleum products pipeline owned by HEP. This project also includes the expansion and extension
of several of HEP's crude gathering systems and crude mainline pipes. Once in service, this system will be capable of transporting
crude oil from southeast New Mexico to third-party common carrier pipelines in west Texas for further transport to major crude
oil markets. This project is estimated to cost approximately $38.0 million and could be fully operational in late 2013.
Cash Flows – Financing Activities
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Net cash flows used for financing activities were $772.8 million for the year ended December 31, 2012 compared to $217.1 million
for the year ended December 31, 2011, an increase of $555.7 million. During the year ended December 31, 2012, we purchased
$209.6 million in common stock, paid $658.1 million in dividends, paid $205.0 million in principal on our senior notes and
recognized $23.4 million excess tax benefits on our equity-based compensation. Also during this period, HEP received $294.8
million in net proceeds upon the issuance of the HEP 6.5% senior notes, paid $185.0 million in principal on the HEP 6.25% senior
notes, received $587.0 million and repaid $366.0 million under the HEP Credit Agreement, paid distributions of $58.8 million to
noncontrolling interests, incurred $3.3 million in deferred financing costs and purchased $5.2 million in HEP common units in
the open market for recipients of its incentive grants. During the year ended December 31, 2011, we purchased $42.8 million in
common stock, paid $252.1 million in dividends, paid $8.2 million in principal on our senior notes and recognized $1.8 million
excess tax benefits on our equity-based compensation. Additionally, we incurred $8.6 million in deferred financing costs. Also
during this period, HEP received $75.8 million in net proceeds upon the issuance of HEP common units, received $118.0 million
and repaid $77.0 million under the HEP Credit Agreement, paid distributions of $50.9 million to noncontrolling interests, incurred
$3.2 million in deferred financing costs and purchased $1.6 million in HEP common units in the open market for recipients of its
incentive grants. UNEV Pipeline joint venture partner contributions received during the years ended December 31, 2012 and 2011
were $6.0 million and $33.5 million, respectively.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Net cash flows used for financing activities were $217.1 million for the year ended December 31, 2011 compared to cash flows
provided by financing activities of $34.5 million for the year ended December 31, 2010, a decrease of $251.6 million. During
2011, we paid $8.2 million principal on our senior notes, purchased $42.8 million in common stock from employees to provide
funds for the payment of payroll and income taxes due upon the vesting of certain share-based incentive awards and also under
the stock repurchase program, paid $252.1 million in dividends and recognized $1.8 million excess tax benefits on our equity-
based compensation. Also during this period, HEP received $75.8 million in net proceeds upon the issuance of HEP common units,
received $118.0 million and repaid $77.0 million under the HEP Credit Agreement, paid distributions of $50.9 million to
noncontrolling interests and purchased $1.6 million in HEP common units in the open market for recipients of its restricted unit
grants. Additionally, $11.8 million in deferred financing costs were incurred in connection with the amendment of HEP's credit
facility in February 2011 and a revision to the HollyFrontier Credit Agreement upon the merger with Frontier. During 2010, we
received and repaid $310.0 million in advances under the HollyFrontier Credit Agreement, paid $31.9 million in dividends and
recognized $1.1 million excess tax benefits on our equity based compensation. Also during this period, HEP received $147.5
million in net proceeds upon the issuance of the HEP 8.25% senior notes, received $66.0 million and repaid $113.0 million under
the HEP Credit Agreement, paid distributions of $48.5 million to noncontrolling interests and purchased $2.7 million in HEP
common units in the open market for recipients of its restricted unit grants. Additionally, $3.1 million in deferred financing costs
were incurred in connection with the issuance of the HEP 8.25% senior notes in March 2010 and an amendment to the HollyFrontier
Credit Agreement. UNEV Pipeline joint venture partner contributions received during the years ended December 31, 2011 and
2010 were $33.5 million and $23.5 million, respectively.
Contractual Obligations and Commitments
The following table presents our long-term contractual obligations as of December 31, 2012 in total and by period due beginning
in 2013. The table below does not include our contractual obligations to HEP under our long-term transportation agreements as
these related-party transactions are eliminated in the Consolidated Financial Statements. A description of these agreements is
provided under “Holly Energy Partners, L.P.” under Items 1 and 2, “Business and Properties.” Also, the table below does not
reflect renewal options on our operating leases that are likely to be exercised.
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Table of Content
Contractual Obligations and Commitments
HollyFrontier Corporation (1) (2)
Long-term debt - principal (3)
Long-term debt - interest (4)
Supply agreements (5)
Transportation agreements (6)
Other long-term obligations
Operating leases
Holly Energy Partners
Long-term debt - principal (7)
Long-term debt - interest (8)
Pipeline operating and right of way leases
Other agreements
Payments Due by Period
Total
Less than
1 Year
1-3 Years
3-5 Years
Over
5 Years
$
473,123
$
1,477
$
3,546
$ 291,326
$ 176,774
219,830
738,608
471,888
16,216
76,222
42,959
283,164
83,515
7,184
22,319
85,324
401,521
162,142
6,582
33,464
69,426
12,688
22,121
41,235
118,664
107,567
2,450
14,431
—
6,008
1,995,887
440,618
692,579
508,985
353,705
871,000
260,951
38,033
16,210
1,186,194
—
42,239
6,909
1,519
50,667
—
421,000
450,000
84,478
13,699
2,967
101,144
79,296
13,668
2,725
516,689
54,938
3,757
8,999
517,694
Total
$ 3,182,081
$ 491,285
$ 793,723
$1,025,674
$ 871,399
(1) We may be required to make cash outlays related to our unrecognized tax benefits. However, due to the uncertainty of the timing of future cash
flows associated with our unrecognized tax benefits, we are unable to make reasonably reliable estimates of the period of cash settlement, if any,
with the respective taxing authorities. Accordingly, unrecognized tax benefits of $12.6 million as of December 31, 2012 have been excluded from
the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 15 “Income Taxes” in the Notes to
Consolidated Financial Statements.
(2) Amounts shown do not include commitments to deliver barrels of crude oil held for other parties at our refineries. We periodically hold crude
oil owned by third parties in the storage tanks at our refineries, which may be run through production. We will be obligated to deliver these stored
barrels of crude oil upon the other party's request.
(3) Our long-term debt consists of the $286.8 million principal balance on our 9.875% senior notes, the $150.0 million principal balance on our 6.875%
senior notes and a long-term financing obligation having a principal balance of $36.3 million at December 31, 2012.
Interest payments consist of interest on our 9.875% and 6.875% senior notes and on our long-term financing obligation.
(4)
(5) We have long-term supply agreements to secure certain quantities of crude oil, feedstock and other resources used in the production process at
market prices. We have estimated future payments under these fixed-quantity agreements expiring between 2014 and 2024 using current market
rates.
(6) Consists of contractual obligations under agreements with third parties for the transportation of crude oil, natural gas and feedstocks to our refineries
and for terminal and storage services under contracts expiring between 2013 and 2024.
(7) HEP's long-term debt consists of the $150.0 million and the $300.0 million principal balances on the 8.25% and 6.5% HEP senior notes and $421.0
(8)
million of outstanding borrowings under the HEP Credit Agreement. The HEP Credit Agreement was amended in June 2012 and expires in 2017.
Interest payments consist of interest on the 6.5% and 8.25% HEP senior notes and interest on long-term debt under the HEP Credit Agreement. The
interest rate on the HEP Credit Agreement debt was 2.46% at December 31, 2012.
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. For additional information, see Note 1 “Description of Business and Summary of Significant
Accounting Policies” in the Notes to Consolidated Financial Statements.
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In the first quarter of 2012, we changed our policy of reporting certain same-party accounts receivable and payable amounts in
the consolidated balance sheets to reflect a net amount due under contractual netting agreements. Prior to this change, we reported
such amounts on a gross basis with a same-party receivable and payable balance presented separately in our balance sheet. GAAP
permits a reporting entity to elect a policy of offsetting same party receivables and payables when such amounts are net settled
under legally enforceable contractual setoff provisions. We believe that a net presentation is preferable because it more appropriately
presents our economic resources (accounts receivable) and claims against us (accounts payable) and the future cash flows associated
with such assets and liabilities. Additionally, we believe a net presentation of such amounts conforms to the predominant practices
used by others in our industry. We have applied this change in accounting principle on a retrospective basis and have recast our
prior period financial statements. See Note 2 “Change in Accounting Policy” in the Notes to Consolidated Financial Statements
for a summary of line items affected in our financial statements.
Variable Interest Entity
HEP is a VIE as defined under GAAP. A VIE is a legal entity whose equity owners do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial support or, as a group, the equity holders lack the power,
through voting rights, to direct the activities that most significantly impact the entity's financial performance, the obligation to
absorb the entity's expected losses or rights to expected residual returns. As the general partner of HEP, we have the sole ability
to direct the activities of HEP that most significantly impact HEP's economic performance. Additionally, since our obligation to
absorb losses and receive benefits from HEP are significant to HEP, we are HEP's primary beneficiary and therefore we consolidate
HEP.
Derivative Instruments
We have commodity price swap, interest rate swap, physical and NYMEX futures contracts that are measured at fair value and
recognized as other assets or liabilities in our consolidated balance sheets. Changes in fair value to derivative instruments are
recognized in earnings unless specific hedge accounting criteria is met. Derivatives meeting certain hedge accounting criteria are
designated as “accounting hedges” and changes in fair value are recorded directly to other comprehensive income. These gains
or losses are reclassified to earnings as the hedging instruments mature. Also, on a quarterly basis, hedge ineffectiveness on our
accounting hedges is measured by comparing the change in fair value of the derivative contracts against the expected future cash
inflows/outflows on the respective transaction being hedged. Any hedge ineffectiveness is recognized in earnings. See Note 14
“Derivative Instruments and Hedging Activities” in the Notes to Consolidated Financial Statements.
Inventory Valuation
Our crude oil and refined product inventories are stated at the lower of cost or market. Cost is determined using the LIFO inventory
valuation methodology and market is determined using current estimated selling prices. Under the LIFO method, the most recently
incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In periods of rapidly declining
prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior
periods. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years when
inventory volumes decline and result in charging cost of sales with LIFO inventory costs generated in prior periods. As of
December 31, 2012, many of our LIFO inventory layers were valued at historical costs that were established in years when price
levels were generally lower; therefore, our results of operation are less sensitive to current market price reductions. As of
December 31, 2012, the excess of current cost over the LIFO inventory value of our crude oil and refined product inventories was
$134.0 million. An actual valuation of inventory under the LIFO method is made at the end of each year based on the inventory
levels at that time. Accordingly, interim LIFO calculations are based on management's estimates of expected year-end inventory
levels and are subject to the final year-end LIFO inventory valuation.
Deferred Maintenance Costs
Our refinery units require regular major maintenance and repairs that are commonly referred to as “turnarounds.” Catalysts used
in certain refinery processes also require routine “change-outs.” The required frequency of the maintenance varies by unit and by
catalyst, but generally is every two to five years. In order to minimize downtime during turnarounds, we often utilize contract
labor as well as our maintenance personnel on a continuous 24 hour basis. Whenever possible, turnarounds are scheduled so that
some units continue to operate while others are down for maintenance. We record the costs of turnarounds as deferred charges
and amortize the deferred costs over the expected periods of benefit.
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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 asset's carrying value
exceeds its fair value, which is generally determined under an income approach using forecasted cash flows associated with the
underlying asset. Estimates of future cash flows 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,
2012, 2011 and 2010.
Intangibles and Goodwill
Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents the excess of the cost
of an acquired entity over the fair value of the assets acquired less liabilities assumed. Goodwill acquired in a business combination
and intangible assets with indefinite useful lives are not amortized while intangible assets with finite useful lives are amortized
on a straight-line basis. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more
frequently if events or changes in circumstances indicate the asset might be impaired. Our analysis entails a comparison of the
estimated fair value of these assets that are derived using a combination of both income (discounted future expected net cash
flows) and comparable market approaches against their respective carrying values. Estimates of future cash flows and fair value
of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates.
There were no impairments of intangible assets or goodwill during the years ended December 31, 2012, 2011 and 2010.
Contingencies
We are 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 matters as well as potential ranges of probable losses. A
determination of the amount of reserves required, if any, for these contingencies is made after careful analysis of each individual
issue. The required reserves may change in the future due to new developments in each matter or changes in approach such as a
change in settlement strategy in dealing with these matters.
RISK MANAGEMENT
We use certain strategies to reduce some commodity price and operational risks. We do not attempt to eliminate all market risk
exposures when we believe that the exposure relating to such risk would not be significant to our future earnings, financial position,
capital resources or liquidity or that the cost of eliminating the exposure would outweigh the benefit.
Commodity Price Risk Management
Our primary market risk is commodity price risk. We are exposed to market risks related to the volatility in crude oil and refined
products, as well as volatility in the price of natural gas used in our refining operations. We periodically enter into derivative
contracts in the form of commodity price swaps and futures contracts to mitigate price exposure with respect to:
•
•
•
•
•
our inventory positions;
natural gas purchases;
costs of crude oil and related grade differentials;
prices of refined products; and
our refining margins.
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As of December 31, 2012, we have the following notional contract volumes related to all outstanding derivative contracts used
to mitigate commodity price risk:
Contract Description
Notional Contract Volumes by Year of Maturity
Total
Outstanding
Notional
2013
2014
2015
2016
2017
Unit of
Measure
Natural gas price swap - long
96,000,000
19,200,000
19,200,000
19,200,000
19,200,000
19,200,000 MMBTU
WTI price swap - long
Ultra-low sulfur diesel price swap -
short
12,930,000
12,565,000
365,000
11,490,000
11,125,000
365,000
Unleaded gasoline price swap - short
1,632,000
1,632,000
WCS price swap - long
WTI price swap - short
NYMEX futures (WTI) - long
6,022,500
6,022,500
150,000
234,000
150,000
234,000
NYMEX futures (WTI) - short
1,091,000
1,091,000
Physical contracts - long
Physical contracts - short
540,000
540,000
540,000
540,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— Barrels
— Barrels
— Barrels
— Barrels
— Barrels
— Barrels
— Barrels
— Barrels
— Barrels
The following sensitivity analysis provides the hypothetical effects of market price fluctuations to the commodity positions hedged
under our derivative contracts:
Change in Underlying Commodity Prices of Hedged Positions
2012
2011
Derivative Fair Value Gain (Loss) at December 31,
10% increase in underlying commodity prices
10% decrease in underlying commodity prices
(In thousands)
(29,230)
29,230
(23,224)
23,224
Interest Rate Risk Management
HEP uses interest rate swaps to manage its exposure to interest rate risk.
As of December 31, 2012, HEP had three interest rate swap contracts that hedge its exposure to the cash flow risk caused by the
effects of LIBOR changes on $305.0 million in credit agreement advances. The first interest rate swap effectively converts $155.0
million of LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.25% as of
December 31, 2012, which equaled an effective interest rate of 3.24%. This swap matures in February 2016. HEP has two additional
interest rate swaps with identical terms which effectively convert $150.0 million of LIBOR based debt to fixed rate debt having
an interest rate of 0.74% plus an applicable margin of 2.25% as of December 31, 2012, which equaled an effective interest rate
of 2.99%. Both of these swap contracts mature in July 2017. These swap contracts have been designated as cash flow hedges.
The market risk inherent in our fixed-rate debt and positions is the potential change arising from increases or decreases in interest
rates as discussed below.
For the fixed rate HollyFrontier Senior Notes and HEP Senior Notes, changes in interest rates will generally affect fair value of
the debt, but not our earnings or cash flows. The outstanding principal, estimated fair value and estimated change in fair value
(assuming a hypothetical 10% change in the yield-to-maturity rates) for these debt instruments as of December 31, 2012 is presented
below:
HollyFrontier Senior Notes
HEP Senior Notes
Outstanding
Principal
Estimated
Fair Value
(In thousands)
Estimated
Change in
Fair Value
436,812
450,000
$
$
470,990
484,125
$
$
12,872
14,250
$
$
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For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31,
2012, outstanding borrowings under the HEP Credit Agreement were $421.0 million. By means of its cash flow hedges, HEP has
effectively converted the variable rate on $305.0 million of outstanding principal to a weighted average fixed rate of 3.12%.
At December 31, 2012, our marketable securities included investments in investment grade, highly-liquid investments with
maturities of three months or less at the time of purchase and hence the interest rate market risk implicit in these cash investments
is low. Due to the short-term nature of our cash and cash equivalents, a hypothetical 10% increase in interest rates would not have
a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect
our operating results or cash flows to be materially affected by the effect of a sudden change in market interest rates on our
investment portfolio.
Our operations are subject to hazards of petroleum processing 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.
Financial information is reviewed on the counterparties in order to review and monitor their financial stability and assess their
ongoing ability to honor their commitments under the derivative contracts. We have not experienced, nor do we expect to experience,
any difficulty in the counterparties honoring their commitments.
We have a risk management oversight committee consisting of members from our senior management. This committee oversees
our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified risks that
may adversely affect the achievement of our goals.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles
Reconciliations of earnings before interest, taxes, depreciation and amortization (“EBITDA”) to amounts reported under
generally accepted accounting principles in financial statements.
Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income attributable
to HollyFrontier stockholders plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and
amortization. EBITDA is not a calculation provided for under GAAP; however, the amounts included in the EBITDA calculation
are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative
to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a
measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented
here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used
by our management for internal analysis and as a basis for financial covenants.
Set forth below is our calculation of EBITDA.
Net income attributable to HollyFrontier stockholders
Add income tax provision
Add interest expense
Subtract interest income
Add depreciation and amortization
EBITDA
Years Ended December 31,
2011
2010
2012
(In thousands)
1,727,172
1,027,962
104,186
(4,786)
242,868
3,097,402
$
$
1,023,397
581,991
78,323
(1,284)
159,707
1,842,134
$
$
103,964
59,312
74,196
(1,168)
117,529
353,833
$
$
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Reconciliations of refinery operating information (non-GAAP performance measures) to amounts reported under generally
accepted accounting principles in financial statements.
Refinery gross margin and net operating margin are non-GAAP performance measures that are used by our management and others
to compare our refining performance to that of other companies in our industry. We believe these margin measures are helpful to
investors in evaluating our refining performance on a relative and absolute basis.
Refinery gross margin per barrel is the difference between average net sales price and average cost of products per barrel of
produced refined products. Net operating margin per barrel is the difference between refinery gross margin and refinery operating
expenses per barrel of produced refined products. These two margins do not include the effect of depreciation and amortization.
Each of these component performance measures can be reconciled directly to our consolidated statements of income.
Other companies in our industry may not calculate these performance measures in the same manner.
Refinery Gross and Net Operating Margins
Below are reconciliations to our consolidated statements of income for (i) net sales, cost of products and operating expenses, in
each case averaged per produced barrel sold, and (ii) net operating margin and refinery gross margin. Due to rounding of reported
numbers, some amounts may not calculate exactly.
Reconciliations of refined product sales from produced products sold to total sales and other revenues
Consolidated
Average sales price per produced barrel sold
Times sales of produced refined products sold (BPD)
Times number of days in period
Refined product sales from produced products sold
Total refined product sales
Add refined product sales from purchased products and rounding (1)
Total refined product sales
Add direct sales of excess crude oil (2)
Add other refining segment revenue (3)
Total refining segment revenue
Add HEP segment sales and other revenues
Add corporate and other revenues
Subtract consolidations and eliminations
Sales and other revenues
Years Ended December 31,
2011
2010
2012
(Dollars in thousands, except per barrel amounts)
$
$
$
$
119.48
431,060
366
18,850,116
18,850,116
572,206
19,422,322
505,971
114,662
20,042,955
288,501
1,048
(241,780)
20,090,724
$
$
$
$
118.82
332,720
365
14,429,833
14,429,833
350,843
14,780,676
558,855
52,899
15,392,430
212,995
1,098
(166,995)
15,439,528
$
$
$
$
91.06
228,140
365
7,582,666
7,582,666
130,866
7,713,532
459,743
113,725
8,287,000
182,093
412
(146,576)
8,322,929
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Table of Content
Reconciliation of average cost of products per produced barrel sold to total cost of products sold
Consolidated
Average cost of products per produced barrel sold
Times sales of produced refined products sold (BPD)
Times number of days in period
Cost of products for produced products sold
Total cost of products for produced products sold
Add refined product costs from purchased products and rounding (1)
Total cost of refined products sold
Add crude oil cost of direct sales of excess crude oil (2)
Add other refining segment cost of products sold (4)
Total refining segment cost of products sold
Subtract consolidations and eliminations
Costs of products sold (exclusive of depreciation and amortization)
Years Ended December 31,
2011
2010
2012
(Dollars in thousands, except per barrel amounts)
$
$
$
$
94.59
431,060
366
14,923,271
14,923,271
572,755
15,496,026
492,790
90,132
16,078,948
(238,305)
15,840,643
$
$
$
$
98.18
332,720
365
11,923,254
11,923,254
351,788
12,275,042
550,619
18,672
12,844,333
(164,255)
12,680,078
$
$
$
$
82.27
228,140
365
6,850,713
6,850,713
131,668
6,982,381
454,566
73,410
7,510,357
(143,208)
7,367,149
Reconciliation of average refinery operating expenses per produced barrel sold to total operating expenses
Consolidated
Average refinery operating expenses per produced barrel sold
Times sales of produced refined products sold (BPD)
Times number of days in period
Refinery operating expenses for produced products sold
Total refinery operating expenses per produced products sold
Add other refining segment operating expenses and rounding (5)
Total refining segment operating expenses
Add HEP segment operating expenses
Add corporate and other costs
Subtract consolidations and eliminations
Operating expenses (exclusive of depreciation and amortization)
Years Ended December 31,
2011
2010
2012
(Dollars in thousands, except per barrel amounts)
5.49
431,060
366
866,146
866,146
37,231
903,377
89,395
2,721
(527)
994,966
$
$
$
$
5.36
332,720
365
650,933
650,933
35,659
686,592
63,029
427
(1,967)
748,081
$
$
$
$
5.08
228,140
365
423,017
423,017
26,573
449,590
53,138
2,172
(486)
504,414
$
$
$
$
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Reconciliation of net operating margin per barrel to refinery gross margin per barrel to total sales and other revenues
Consolidated
Net operating margin per barrel
Add average refinery operating expenses per produced barrel
Refinery gross margin per barrel
Add average cost of products per produced barrel sold
Average sales price per produced barrel sold
Times sales of produced refined products sold (BPD)
Times number of days in period
Refined product sales from produced products sold
Total refined product sales from produced products sold
Add refined product sales from purchased products and rounding (1)
Total refined product sales
Add direct sales of excess crude oil (2)
Add other refining segment revenue (3)
Total refining segment revenue
Add HEP segment sales and other revenues
Add corporate and other revenues
Subtract consolidations and eliminations
Sales and other revenues
Years Ended December 31,
2011
2010
2012
(Dollars in thousands, except per barrel amounts)
$
$
$
$
$
19.40
5.49
24.89
94.59
119.48
431,060
366
18,850,116
18,850,116
572,206
19,422,322
505,971
114,662
20,042,955
288,501
1,048
(241,780)
20,090,724
$
$
$
$
$
15.28
5.36
20.64
98.18
118.82
332,720
365
14,429,833
14,429,833
350,843
14,780,676
558,855
52,899
15,392,430
212,995
1,098
(166,995)
15,439,528
$
$
$
$
$
3.71
5.08
8.79
82.27
91.06
228,140
365
7,582,666
7,582,666
130,866
7,713,532
459,743
113,725
8,287,000
182,093
412
(146,576)
8,322,929
(1) We purchase finished products when opportunities arise that provide a profit on the sale of such products, or to meet delivery
commitments.
(2) We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities in excess of our needs are sold at market
prices to purchasers of crude oil that are recorded on a gross basis with the sales price recorded as revenues and the corresponding
acquisition cost as inventory and then upon sale as cost of products sold. Additionally, at times we enter into buy/sell exchanges of
crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost.
(3) Other refining segment revenue includes the incremental revenues associated with NK Asphalt and miscellaneous revenue.
(4) Other refining segment cost of products sold includes the incremental cost of products for NK Asphalt and miscellaneous costs.
(5) Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses
of NK Asphalt.
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Item 8. Financial Statements and Supplementary Data
MANAGEMENT'S REPORT ON ITS ASSESSMENT OF THE COMPANY'S INTERNAL CONTROL OVER
FINANCIAL REPORTING
Management of HollyFrontier Corporation (the “Company”) 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 Company's internal control over financial reporting as of December 31, 2012 using the criteria for
effective control over financial reporting established in “Internal Control - Integrated Framework” issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concludes that, as of December 31,
2012, the Company maintained effective internal control over financial reporting.
The Company's independent registered public accounting firm has issued an attestation report on the effectiveness of the Company's
internal control over financial reporting as of December 31, 2012. That report appears on page 55.
54
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
and Stockholders of HollyFrontier Corporation
We have audited HollyFrontier Corporation's internal control over financial reporting as of December 31, 2012, based on criteria
established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission, (the “COSO criteria”). HollyFrontier Corporation's 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 Management's Report on its Assessment of the Company's Internal Control over Financial Reporting. Our
responsibility is to express an opinion on the Company's 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 company's 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 company's 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 company's 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, HollyFrontier Corporation maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2012, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of HollyFrontier Corporation as of December 31, 2012 and 2011, and the related consolidated
statements of income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31,
2012 and our report dated February 27, 2013 expressed an unqualified opinion thereon.
/s/
ERNST & YOUNG LLP
Dallas, Texas
February 27, 2013
55
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2012 and 2011
Consolidated Statements of Income for the years ended
December 31, 2012, 2011 and 2010
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2012, 2011 and 2010
Consolidated Statements of Cash Flows for the years ended
December 31, 2012, 2011 and 2010
Consolidated Statements of Equity for the years ended
December 31, 2012, 2011 and 2010
Notes to Consolidated Financial Statements
Page
Reference
57
58
59
60
61
62
63
56
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
and Stockholders of HollyFrontier Corporation
We have audited the accompanying consolidated balance sheets of HollyFrontier Corporation (the “Company”) as of December 31,
2012 and 2011, and the related consolidated statements of income, comprehensive income, cash flows and equity for each of the
three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's 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 includes examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position
of HollyFrontier Corporation at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for
each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, the Company has elected to change its method of accounting for
accounts receivables and payables with the same counterparty where a right of setoff exists from a gross presentation to a net
presentation in the consolidated balance sheets.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
HollyFrontier Corporation's internal control over financial reporting as of December 31, 2012, 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 27, 2013 expressed an unqualified opinion thereon.
Dallas, Texas
February 27, 2013
/s/
ERNST & YOUNG LLP
57
Table of Content
ASSETS
Current assets:
HOLLYFRONTIER CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
Cash and cash equivalents (HEP: $5,237 and $6,369, respectively)
Marketable securities
Accounts receivable: Product and transportation (HEP: $38,097 and $37,290, respectively)
Crude oil resales
Inventories: Crude oil and refined products
Materials, supplies and other (HEP: $1,259 and $1,483, respectively)
Income taxes receivable
Prepayments and other (HEP: $2,360 and $2,246, respectively)
Total current assets
Properties, plants and equipment, at cost (HEP: $1,155,710 and $1,099,579, respectively)
Less accumulated depreciation (HEP: $(141,154) and $(93,200), respectively)
Marketable securities (long-term)
Other assets: Turnaround costs
Goodwill (HEP: $288,991 and $288,991, respectively)
Intangibles and other (HEP: $76,300 and $75,902, respectively)
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (HEP: $12,030 and $21,709, respectively)
Income taxes payable
Accrued liabilities (HEP: $23,705 and $16,006, respectively)
Deferred income tax liabilities
Total current liabilities
Long-term debt (HEP: $864,673 and $598,761, respectively)
Deferred income taxes
Other long-term liabilities (HEP: $28,683 and $4,000, respectively)
Equity:
HollyFrontier stockholders’ equity:
Preferred stock, $1.00 par value – 5,000,000 shares authorized; none issued
Common stock $.01 par value – 320,000,000 shares authorized; 255,962,866 shares issued as of
December 31, 2012 and December 31, 2011
Additional capital
Retained earnings
Accumulated other comprehensive income (loss)
Common stock held in treasury, at cost – 52,411,370 and 46,630,220 shares as of
December 31, 2012 and December 31, 2011, respectively
Total HollyFrontier stockholders’ equity
Noncontrolling interest
Total equity
Total liabilities and equity
December 31,
2012
2011
As Adjusted
(See Note 2)
$
$
$
$
1,757,699
630,586
587,728
46,502
634,230
1,238,678
80,954
1,319,632
74,957
53,161
4,470,265
3,943,114
(748,414)
3,194,700
5,116
151,764
2,338,302
168,850
2,658,916
10,328,997
1,314,151
—
195,077
145,216
1,654,444
1,336,238
536,670
158,987
—
2,560
3,911,353
3,054,769
(8,425)
(907,303)
6,052,954
589,704
6,642,658
10,328,997
$
$
$
$
1,578,904
211,639
703,691
5,166
708,857
1,052,084
62,535
1,114,619
87,277
219,450
3,920,746
3,631,787
(578,882)
3,052,905
50,067
57,060
2,336,510
158,955
2,552,525
9,576,243
1,504,694
40,366
169,940
175,683
1,890,683
1,214,742
463,721
171,197
—
2,563
3,859,367
1,964,656
77,873
(700,449)
5,204,010
631,890
5,835,900
9,576,243
Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of December 31, 2012 and December 31,
2011. HEP is a consolidated variable interest entity.
In July 2012, HEP acquired our 75% interest in UNEV Pipeline, LLC (“UNEV”). We have recast HEP's asset and liability balances at December 31,
2011 presented parenthetically above to include balances attributable to UNEV. See Note 4.
See accompanying notes.
58
Table of Content
HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)
Sales and other revenues
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and
amortization)
Operating expenses (exclusive of depreciation and amortization)
General and administrative expenses (exclusive of depreciation
and amortization)
Depreciation and amortization
Total operating costs and expenses
Income from operations
Other income (expense):
Earnings of equity method investments
Interest income
Interest expense
Gain on sale of marketable equity securities
Merger transaction costs
Income before income taxes
Income tax provision:
Current
Deferred
Net income
Less net income attributable to noncontrolling interest
Net income attributable to HollyFrontier stockholders
Earnings per share attributable to HollyFrontier stockholders:
Basic
Diluted
Average number of common shares outstanding:
Basic
Diluted
See accompanying notes.
Years Ended December 31,
2011
2010
2012
$
20,090,724
$
15,439,528
$
8,322,929
15,840,643
12,680,078
994,966
748,081
128,101
242,868
120,114
159,707
17,206,578
13,707,980
2,884,146
1,731,548
7,367,149
504,414
70,839
117,529
8,059,931
262,998
2,923
4,786
2,300
1,284
2,393
1,168
(104,186)
(78,323)
(74,196)
326
—
(96,151)
—
(15,114)
(89,853)
2,787,995
1,641,695
932,554
95,408
1,027,962
1,760,033
32,861
1,727,172
8.41
8.38
$
$
$
590,851
(8,860)
581,991
1,059,704
36,307
1,023,397
6.46
6.42
$
$
$
$
$
$
—
—
(70,635)
192,363
35,472
23,840
59,312
133,051
29,087
103,964
0.98
0.97
205,289
206,184
158,486
159,294
106,436
107,218
59
Table of Content
HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Net income
Other comprehensive income (loss):
Securities available-for-sale:
Years Ended December 31,
2012
2011
2010
$
1,760,033
$
1,059,704
$
133,051
Unrealized gain (loss) on available-for-sale securities
Reclassification adjustment to net income on sale or maturity of
marketable securities
Net unrealized gain (loss) on available-for-sale securities
Unrealized gain (loss), net of reclassifications from contract
settlements of hedging instruments
179
(415)
(236)
(530)
14
(516)
(191,039)
176,936
Pension plan curtailment
Change in minimum pension liability
Change in retirement medical obligation
Other comprehensive income (loss) before income taxes
Income tax expense (benefit)
Other comprehensive income (loss)
Total comprehensive income
Less noncontrolling interest in comprehensive income
Comprehensive income attributable to HollyFrontier
stockholders
See accompanying notes.
114
—
114
(923)
—
(1,470)
(238)
(2,517)
(348)
(2,169)
130,882
27,464
7,102
(9,161)
53,450
(139,884)
(54,950)
(84,934)
—
(71)
(3,515)
172,834
66,138
106,696
1,675,099
1,166,400
34,225
39,122
$
1,640,874
$
1,127,278
$
103,418
60
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HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31,
2011
2010
2012
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
$
1,760,033
$ 1,059,704
$
133,051
As Adjusted (See Note 2)
Depreciation and amortization
Earnings of equity method investments, net of distributions
Gain on sale of marketable equity securities
Deferred income taxes
Equity-based compensation expense
Change in fair value – derivative instruments
(Increase) decrease in current assets:
Accounts receivable
Inventories
Income taxes receivable
Prepayments and other
Increase (decrease) in current liabilities:
Accounts payable
Income taxes payable
Accrued liabilities
Turnaround expenditures
Other, net
Net cash provided by operating activities
Cash flows from investing activities:
Additions to properties, plants and equipment
Additions to properties, plants and equipment – HEP
Increase in cash due to merger with Frontier
Investment in Sabine Biofuels
Purchases of marketable securities
Sales and maturities of marketable securities
Net cash provided by (used for) investing activities
Cash flows from financing activities:
Borrowings under credit agreement
Repayments under credit agreement
Borrowings under credit agreement – HEP
Repayments under credit agreement – HEP
Net proceeds from issuance of senior notes – HEP
Principal tender on senior notes
Principal tender on senior notes – HEP
Proceeds from issuance of common units – HEP
Purchase of treasury stock
Structured stock repurchase arrangement
Contribution from joint venture partner
Dividends
Distributions to noncontrolling interest
Excess tax benefit from equity-based compensation
Purchase of units for incentive grants – HEP
Deferred financing costs
Other
Net cash provided by (used for) financing activities
Cash and cash equivalents:
Increase for the period
Beginning of period
End of period
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest
Income taxes
See accompanying notes.
61
242,868
701
(326)
95,408
39,203
52,335
71,627
(205,013)
19,056
(9,366)
(194,051)
(40,366)
(39,851)
(159,707)
30,136
1,662,687
(290,334)
(44,929)
—
(2,000)
(671,552)
297,711
(711,104)
—
—
587,000
(366,000)
294,750
(205,000)
(185,000)
—
(209,600)
8,620
6,000
(658,085)
(58,788)
23,361
(5,240)
(3,305)
(1,501)
(772,788)
159,707
387
—
(8,860)
26,825
306
373,591
(56,828)
(36,394)
(14,214)
(251,428)
72,091
60,467
(32,023)
(14,940)
1,338,391
(158,026)
(216,215)
872,739
(9,125)
(561,899)
301,020
228,494
—
—
118,000
(77,000)
—
(8,203)
—
75,815
(42,795)
—
33,500
(252,133)
(50,874)
1,804
(1,641)
(11,815)
(1,740)
(217,082)
178,795
1,578,904
1,757,699
1,349,803
229,101
$ 1,578,904
101,709
983,618
$
$
78,483
552,487
$
$
$
$
$
$
117,529
482
—
23,840
11,498
1,464
43,437
(96,854)
(14,990)
369
70,279
—
22,414
(34,966)
5,702
283,255
(103,722)
(109,510)
—
—
—
—
(213,232)
310,000
(310,000)
66,000
(113,000)
147,540
—
—
—
(1,368)
—
23,500
(31,868)
(48,493)
(1,094)
(2,704)
(3,121)
(910)
34,482
104,505
124,596
229,101
66,674
62,084
Table of Content
HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
HollyFrontier Stockholders' Equity
Balance at December 31, 2009
Net income
Dividends
Distributions to noncontrolling
interest holders
Other comprehensive loss, net of
tax
Contribution from joint venture
partner
Issuance of common stock and tax
benefit on exercise of stock
options
Issuance of common stock under
incentive compensation plans, net
of forfeitures
Equity-based compensation, net of
tax benefit
Purchase of treasury stock
Other
Balance at December 31, 2010
Net income
Dividends
Distribution to noncontrolling
interest holders
Other comprehensive income, net
of tax
Issuance of common stock upon
merger with Frontier Oil
Corporation
Allocated equity on HEP common
unit issuances, net of tax
Contribution from joint venture
partner
Issuance of common stock under
incentive compensation plans, net
of forfeitures
Equity-based compensation, net of
tax benefit
Purchase of treasury stock
Other
Balance at December 31, 2011
Net income
Dividends
Distributions to noncontrolling
interest holders
Other comprehensive income, net
of tax
Allocated equity on HEP common
unit issuances, net of tax
Contribution from joint venture
partner
Issuance of common stock under
incentive compensation plans, net
of forfeitures
Equity-based compensation, net of
tax benefit
Purchase of treasury stock
Net proceeds received under
structured share repurchase
arrangement
Purchase of HEP units for
restricted grants
$
$
Accumulated
Other
Comprehensive
Income (Loss)
Treasury
Stock
Non-
controlling
Interest
Total Equity
Common
Stock
$
1,527
—
—
Additional
Capital
$ 194,802
—
—
Retained
Earnings
$1,134,341
103,964
(31,977)
—
—
—
534
(9,494)
7,773
—
—
—
—
—
—
—
—
$ 193,615
—
—
$1,206,328
— 1,023,397
(265,069)
—
—
—
—
—
(1)
—
—
—
1,526
—
—
—
—
—
—
1,037
3,704,203
—
—
—
—
(44,885)
—
(20,150)
26,584
—
—
—
—
—
—
—
—
—
2,563
—
—
—
—
$ 3,859,367
—
—
$1,964,656
— 1,727,172
(637,059)
—
$
—
—
—
—
—
—
11,469
—
(3)
(27,809)
—
—
—
—
59,706
—
8,620
—
—
—
—
—
—
—
—
—
—
$
(25,700) $ (685,931) $
—
—
—
(546)
—
—
—
—
—
—
—
—
—
—
—
—
9,495
—
(1,368)
—
$
(26,246) $ (677,804) $
—
—
—
103,881
—
238
—
—
—
—
—
77,873
—
—
—
(86,298)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
20,150
—
(42,795)
—
$ (700,449) $
—
—
—
—
—
—
27,812
—
(234,666)
—
—
$
588,742
29,087
—
1,207,781
133,051
(31,977)
(48,493)
(48,493)
(1,623)
(2,169)
23,500
23,500
—
—
534
—
2,215
—
(2,708)
590,720
36,307
—
$
9,988
(1,368)
(2,708)
1,288,139
1,059,704
(265,069)
(50,874)
(50,874)
2,815
106,696
—
3,705,240
16,852
36,500
(27,795)
36,500
—
—
2,046
—
(2,476)
631,890
32,861
—
(58,788)
$
28,630
(42,795)
(2,476)
5,835,900
1,760,033
(637,059)
(58,788)
1,364
(84,934)
(18,768)
(7,299)
3,000
3,000
—
2,858
—
—
—
62,564
(234,666)
8,620
(4,713)
(4,713)
Balance at December 31, 2012
$
2,560
$ 3,911,353
$3,054,769
$
(8,425) $ (907,303) $
589,704
$
6,642,658
See accompanying notes.
62
Table of Content
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: Description of Business and Summary of Significant Accounting Policies
Description of Business: References herein to HollyFrontier Corporation (“HollyFrontier”) include HollyFrontier and its
consolidated subsidiaries. In accordance with the Securities and Exchange Commission’s (“SEC”) “Plain English” guidelines, this
Annual Report on Form 10-K has been written in the first person. In these financial statements, the words “we,” “our,” “ours” and
“us” refer only to HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any
other person, with certain exceptions. Generally, the words “we,” “our,” “ours” and “us” include Holly Energy Partners, L.P.
(“HEP”) and its subsidiaries as consolidated subsidiaries of HollyFrontier, unless when used in disclosures of transactions or
obligations between HEP and HollyFrontier or its other subsidiaries. These financial statements contain certain disclosures of
agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of HollyFrontier.
When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.
We merged with Frontier Oil Corporation (“Frontier”) on July 1, 2011. Concurrent with the merger, we changed our name from
Holly Corporation (“Holly”) to HollyFrontier and changed the ticker symbol for our common stock traded on the New York Stock
Exchange to “HFC” (see Note 3). Accordingly, these financial statements include Frontier, its consolidated subsidiaries and the
operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date.
We are principally an independent petroleum refiner that produces high-value light products such as gasoline, diesel fuel, jet fuel,
specialty lubricant products, and specialty and modified asphalt. We own and operate petroleum refineries that serve markets
throughout the Mid-Continent, Southwest and Rocky Mountain regions of the United States. As of December 31, 2012, we:
•
•
•
•
owned and operated a petroleum refinery in El Dorado, Kansas (the “El Dorado Refinery”), two refinery facilities located
in Tulsa, Oklahoma (collectively, the “Tulsa Refineries”), a refinery in Artesia, New Mexico that is operated in conjunction
with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico
(collectively, the “Navajo Refinery”), a refinery located in Cheyenne, Wyoming (the “Cheyenne Refinery”) and a refinery
in Woods Cross, Utah (the “Woods Cross Refinery”);
owned and operated NK Asphalt Partners (“NK Asphalt”) which operates various asphalt terminals in Arizona and New
Mexico;
owned Ethanol Management Company (“EMC”), a products terminal and blending facility near Denver, Colorado and
a 50% interest in Sabine Biofuels II, LLC (“Sabine Biofuels”), a biodiesel production facility located in Port Arthur,
Texas; and
owned a 44% interest in HEP, a consolidated variable interest entity (“VIE”), which includes our 2% general partner
interest. HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines and terminal,
tankage and loading rack facilities that principally support our refining and marketing operations in the Mid-Continent,
Southwest and Rocky Mountain regions of the United States and Alon USA, Inc.'s (“Alon”) refinery in Big Spring, Texas.
Additionally, HEP owns a 75% interest in UNEV Pipeline, L.L.C. (“UNEV”), which owns a 12-inch refined products
pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and
North Las Vegas areas (the “UNEV Pipeline”) and a 25% interest in SLC Pipeline LLC (the “SLC Pipeline”), a 95-mile
intrastate pipeline system that serves refineries in the Salt Lake City area.
Principles of Consolidation: Our consolidated financial statements include our accounts and the accounts of partnerships and
joint ventures that we control through an ownership interest greater than 50% or through a controlling financial interest with respect
to variable interest entities. All significant intercompany transactions and balances have been eliminated.
Variable Interest Entity: HEP is a VIE as defined under U.S. generally accepted accounting principles (“GAAP”). A VIE is a legal
entity whose equity owners do not have sufficient equity at risk for the entity to finance its activities without additional subordinated
financial support or, as a group, the equity holders lack the power, through voting rights, to direct the activities that most significantly
impact the entity's financial performance, the obligation to absorb the entity's expected losses or rights to expected residual returns.
As the general partner of HEP, we have the sole ability to direct the activities of HEP that most significantly impact HEP's economic
performance. Additionally, since our obligation to absorb losses and receive benefits from HEP are significant to HEP, we are
HEP's primary beneficiary and therefore, we consolidate HEP. Our revaluation of HEP's assets and liabilities upon reconsolidation
in 2008 resulted in basis adjustments to our consolidated HEP balances. Therefore, our reported amounts for HEP may not agree
to amounts reported in HEP's periodic public filings.
63
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Use of Estimates: The preparation of financial statements in accordance with GAAP requires management to make estimates and
assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from
those estimates.
Cash Equivalents: We consider all highly liquid instruments with a maturity of three months or less at the date of purchase to be
cash equivalents. Cash equivalents are stated at cost, which approximates market value and are primarily invested in highly-rated
instruments issued by government or municipal entities with strong credit standings.
Marketable Securities: We consider all marketable debt securities with maturities greater than three months at the date of purchase
to be marketable securities. Our marketable securities consist of certificates of deposit, commercial paper, corporate debt securities
and government and municipal debt securities with the maximum maturity or put date of any individual issue generally not more
than two years, while the maximum duration of the portfolio of investments is not greater than one year. These instruments are
classified as available-for-sale, and as a result, are reported at fair value. Unrealized gains and losses, net of related income taxes,
are reported as a component of accumulated other comprehensive income.
Accounts Receivable: The majority of our accounts receivable are due from companies in the petroleum industry. Credit is extended
based on evaluation of the customer's financial condition and in certain circumstances, collateral, such as letters of credit or
guarantees, is required. We reserve for doubtful accounts based on current sales levels as well as specific accounts identified as
high risk, which historically have been minimal. Credit losses are charged to the allowance for doubtful accounts when an account
is deemed uncollectible. Our allowance for doubtful accounts was $2.5 million and $3.5 million at December 31, 2012 and 2011,
respectively.
Accounts receivable attributable to crude oil resales generally represent the sell side of excess crude oil sales to other purchasers
and / or users in cases when our crude oil supplies are in excess of our immediate needs as well as certain reciprocal buy / sell
exchanges of crude oil. At times we enter into such buy / sell exchanges to facilitate the delivery of quantities to certain locations.
In many cases, we enter into net settlement agreements relating to the buy/sell arrangements, which may mitigate credit risk.
Inventories: Inventories are stated at the lower of cost, using the last-in, first-out (“LIFO”) method for crude oil unfinished and
finished refined products and the average cost method for materials and supplies, or market. Cost, consisting of raw material,
transportation and conversion costs, is determined using the LIFO inventory valuation methodology and market is determined
using current estimated selling prices. Under the LIFO method, the most recently incurred costs are charged to cost of sales and
inventories are valued at the earliest acquisition costs. In periods of rapidly declining prices, LIFO inventories may have to be
written down to market value due to the higher costs assigned to LIFO layers in prior periods. In addition, the use of the LIFO
inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of
charging cost of sales with LIFO inventory costs generated in prior periods. An actual valuation of inventory under the LIFO
method is made at the end of each year based on the inventory levels at that time. Accordingly, interim LIFO calculations are based
on management's estimates of expected year-end inventory levels and are subject to the final year-end LIFO inventory valuation.
Derivative Instruments: All derivative instruments are recognized as either assets or liabilities in our consolidated balance sheets
and are measured at fair value. Changes in the derivative instrument's fair value are recognized in earnings unless specific hedge
accounting criteria are met. See Note 14 for additional information.
Long-lived assets: We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets.
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 asset's carrying value exceeds its fair value, which is
generally determined under an income approach using the forecasted cash flows associated with the underlying asset. Estimates
of future cash flows 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, 2012, 2011 and 2010.
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 long-lived assets. The fair value of the estimated cost to
retire a tangible long-lived asset is recorded as a liability with the associated retirement costs capitalized as part of the asset's
carrying amount in the period in which it 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 liability's fair value.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Our asset retirement obligations were $18.1 million and $14.4 million at December 31, 2012 and 2011, respectively, which are
included in “Other long-term liabilities” in our consolidated balance sheets. Accretion expense was insignificant for the years
ended December 31, 2012, 2011 and 2010.
Intangibles and Goodwill: Intangible assets are assets (other than financial assets) that lack physical substance. Goodwill represents
the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Goodwill acquired in
a business combination and intangible assets with indefinite useful lives are not amortized while, intangible assets with finite useful
lives are amortized on a straight-line basis. Goodwill and intangible assets not subject to amortization are tested for impairment
annually or more frequently if events or changes in circumstances indicate the asset might be impaired. Our analysis entails a
comparison of the estimated fair value of these assets that are derived using a combination of both income (discounted future
expected net cash flows) and comparable market approaches against their respective carrying values. Estimates of future cash
flows and fair value of assets require subjective assumptions with regard to future operating results and actual results could differ
from those estimates.
In addition to goodwill, our consolidated HEP assets include a third-party transportation agreement that currently generates
minimum annual cash inflows of $24.4 million and has an expected remaining term through 2035. The transportation agreement
is being amortized on a straight-line basis through 2035 that results in annual amortization expense of $2.0 million. The balance
of this transportation agreement was $44.5 million and $46.5 million at December 31, 2012 and 2011, respectively, and is presented
net of accumulated amortization of $15.7 million and $13.7 million, respectively, in “Intangibles and other” in our consolidated
balance sheets. There were no impairments of intangible assets or goodwill during the years ended December 31, 2012, 2011 and
2010.
Investments in Joint Ventures: We consolidate the financial and operating results of joint ventures in which we have an ownership
interest of greater than 50% and use the equity method of accounting for investments in which we have a 50% or less ownership
interest. Under the equity method of accounting, we record our pro-rata share of earnings, and contributions to and distributions
from joint ventures as adjustments to our investment balance.
HEP has a 25% joint venture interest in the SLC Pipeline that is accounted for using the equity method of accounting. As of
December 31, 2012, HEP's underlying equity in the SLC Pipeline was $60.0 million compared to its recorded investment balance
of $25.0 million, a difference of $35.0 million. This is attributable to the difference between HEP's contributed capital and its
allocated equity at formation of the SLC Pipeline. This difference is being amortized as an adjustment to HEP's pro-rata share of
earnings.
Revenue Recognition: Refined product sales and related cost of sales are recognized when products are shipped and title has
passed to customers. HEP recognizes pipeline transportation revenues as products are shipped through its pipelines. All revenues
are reported inclusive of shipping and handling costs billed and exclusive of any taxes billed to customers. Shipping and handling
costs incurred are reported in cost of products sold.
Depreciation: Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 20 to
25 years for refining, pipeline and terminal facilities, 10 to 40 years for buildings and improvements, 5 to 30 years for other fixed
assets and 5 years for vehicles.
Cost Classifications: Costs of products sold include the cost of crude oil, other feedstocks, blendstocks and purchased finished
products, inclusive of transportation costs. We purchase crude oil that at times exceeds the supply needs of our refineries. Quantities
in excess of our needs are sold at market prices to purchasers of crude oil that are recorded on a gross basis with the sales price
recorded as revenues and the corresponding acquisition cost as cost of products sold. Additionally, we enter into buy/sell exchanges
of crude oil with certain parties to facilitate the delivery of quantities to certain locations that are netted at carryover cost. Operating
expenses include direct costs of labor, maintenance materials and services, utilities, marketing expense and other direct operating
costs. General and administrative expenses include compensation, professional services and other support costs.
Deferred Maintenance Costs: Our refinery units require regular major maintenance and repairs which are commonly referred to
as “turnarounds.” Catalysts used in certain refinery processes also require regular “change-outs.” The required frequency of the
maintenance varies by unit and by catalyst, but generally is every two to five years. Turnaround costs are deferred and amortized
over the period until the next scheduled turnaround. Other repairs and maintenance costs are expensed when incurred.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Environmental Costs: Environmental costs are charged to operating expenses 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.
Such estimates require judgment with respect to costs, timeframe and extent of required remedial and clean-up activities and are
subject to periodic adjustments based on currently available information. Recoveries of environmental costs through insurance,
indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.
Contingencies: We are 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 matters as well as potential ranges of
probable losses. A determination of the amount of reserves required, if any, for these contingencies is made after careful analysis
of each individual issue. The required reserves may change in the future due to new developments in each matter or changes in
approach such as a change in settlement strategy in dealing with these matters.
Income Taxes: Provisions for income taxes include deferred taxes resulting from temporary differences in income for financial
and tax purposes, using the liability method of accounting for income taxes. The liability method requires the effect of tax rate
changes on current and accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The
liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the
assets will be realized.
Potential interest and penalties related to income tax matters are recognized in income tax expense. We believe we have appropriate
support for the income tax positions taken and to be taken on our income tax returns and that our accruals for tax liabilities are
adequate for all open years based on an assessment of many factors, including past experience and interpretations of tax law applied
to the facts of each matter.
NOTE 2: Change in Accounting Principle
In the first quarter of 2012, we changed our policy of reporting certain same-party accounts receivable and payable balances in
the consolidated balance sheets to reflect a net amount due under contractual netting agreements. Prior to this change, we reported
such balances on a gross basis with a same-party receivable and payable balance presented separately in our balance sheet. GAAP
permits a reporting entity to elect a policy of offsetting same-party receivables and payables when such amounts are net settled
under legally enforceable contractual setoff provisions. We believe that a net presentation is preferable because it more appropriately
presents our economic resources (accounts receivable) and claims against us (accounts payable) and the future cash flows associated
with such assets and liabilities. Additionally, we believe a net presentation of such amounts conforms to the predominant practices
used by other companies in our industry. We have applied this change in accounting principle on a retrospective basis and have
recast our prior period financial statements.
The following table summarizes the line items affected in our consolidated balance sheet at December 31, 2011:
Accounts receivable: Crude oil resales
Total current assets
Total assets
Accounts payable
Total current liabilities
Total liabilities and equity
As Originally
Reported
$
$
$
$
743,544
4,659,124
10,314,621
2,243,072
2,629,061
10,314,621
$
$
$
$
As Adjusted
(In thousands)
Effect of Change
5,166
3,920,746
9,576,243
1,504,694
1,890,683
9,576,243
$
$
$
$
(738,378)
(738,378)
(738,378)
(738,378)
(738,378)
(738,378)
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The following table summarizes the line items affected in our consolidated statements of cash flows for the years ended
December 31, 2011 and 2010:
December 31, 2011
(Increase) decrease in current assets:
Accounts receivable
Increase (decrease) in current liabilities:
Accounts payable
December 31, 2010
(Increase) decrease in current assets:
Accounts receivable
Increase (decrease) in current liabilities:
Accounts payable
As Originally
Reported
As Adjusted
(In thousands)
Effect of Change
$
$
$
$
286,737
$
373,591
$
86,854
(164,574)
$
(251,428)
$
(86,854)
(228,466)
$
43,437
342,182
$
70,279
$
$
271,903
(271,903)
At December 31, 2012, our accounts payable balance is presented net of $723.4 million in crude oil receivables subject to contractual
setoff provisions. There was no cumulative impact to retained earnings since this change in accounting principle did not affect
earnings.
NOTE 3: Holly-Frontier Merger
On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination between us
and Frontier. On July 1, 2011, North Acquisition, Inc., a direct wholly-owned subsidiary of Holly, merged with and into Frontier,
with Frontier surviving as a wholly-owned subsidiary of Holly. Subsequent to the merger and following approval by the post-
closing board of directors of HollyFrontier, Frontier merged with and into HollyFrontier, with HollyFrontier continuing as the
surviving corporation.
In accordance with the merger agreement, we issued approximately 102.8 million shares of HollyFrontier common stock in
exchange for outstanding shares of Frontier common stock to former Frontier stockholders. Each outstanding share of Frontier
common stock was converted into 0.4811 shares of HollyFrontier common stock with any fractional shares paid in cash. The
aggregate consideration paid in connection with the merger was approximately $3.7 billion. This is based on our July 1, 2011
market closing price of $35.93 and includes a portion of the fair value of the outstanding equity-based awards assumed from
Frontier that relates to pre-merger services.
Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011,
which consists of crude oil refining and the wholesale marketing of refined petroleum products produced at the El Dorado and
Cheyenne Refineries, which serve markets in the Rocky Mountain and Plains States regions of the United States. Assuming the
merger had been consummated on January 1, 2010, pro forma revenues, net income and basic and diluted earnings per share are
as follows:
Years Ended December 31,
2011
2010
(In thousands, except per share amounts)
(Unaudited)
Sales and other revenues
Net income attributable to HollyFrontier stockholders
Basic earnings per share
Diluted earnings per share
$
$
$
$
19,418,709
1,335,257
6.37
6.35
$
$
$
$
14,207,835
179,979
0.86
0.86
Adjustments made to derive pro forma net income primarily relate to depreciation and amortization expense to reflect our new
basis in the legacy Frontier refining facilities.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
For the year ended December 31, 2011, we recognized $15.1 million in merger transaction costs that are presented separately in
our income statements and primarily relate to legal, advisory and other professional fees incurred since the announcement of our
merger agreement in February 2011. This does not include costs to integrate the operations of the combined company. For the year
ended December 31, 2011, general and administrative expenses included $26.5 million in integration and severance costs associated
with the merger integration.
NOTE 4: Holly Energy Partners
HEP, a consolidated VIE, is a publicly held master limited partnership that was formed to acquire, own and operate the petroleum
product and crude oil pipeline and terminal, tankage and loading rack facilities that support our refining and marketing operations
in the Mid-Continent, Southwest and Rocky Mountain regions of the United States. HEP also owns and operates refined product
pipelines and terminals, located primarily in Texas, that serve Alon's refinery in Big Spring, Texas.
As of December 31, 2012, we owned a 44% interest in HEP, including the 2% general partner interest. We are the primary beneficiary
of HEP's earnings and cash flows and therefore we consolidate HEP. See Note 22 for supplemental guarantor/non-guarantor
financial information, including HEP balances included in these consolidated financial statements. All intercompany transactions
with HEP are eliminated in our consolidated financial statements.
HEP has two primary customers (including us) and generates revenues by charging tariffs for transporting petroleum products and
crude oil though its pipelines, by charging fees for terminalling refined products and other hydrocarbons, and storing and providing
other services at its storage tanks and terminals. Under our long-term transportation agreements with HEP (discussed further
below), we accounted for 84% of HEP’s total revenues for the year ended December 31, 2012. We do not provide financial or
equity support through any liquidity arrangements and / or debt guarantees to HEP.
HEP has outstanding debt under a senior secured revolving credit agreement and its senior notes. With the exception of the assets
of HEP Logistics Holdings, L.P., one of our wholly-owned subsidiaries and HEP’s general partner, HEP’s creditors have no recourse
to our assets. Any recourse to HEP’s general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which
other than its investment in HEP, are not significant. Furthermore, our creditors have no recourse to the assets of HEP and its
consolidated subsidiaries. See Note 13 for a description of HEP’s debt obligations.
At December 31, 2012, we have an agreement to pledge up to 6.0 million of our HEP common units to collateralize certain crude
oil purchases. These units represent a 21% ownership interest in HEP.
HEP has risk associated with its operations. If a major customer of HEP were to terminate its contracts or fail to meet desired
shipping or throughput levels for an extended period of time, revenue would be reduced and HEP could suffer substantial losses
to the extent that a new customer is not found. In the event that HEP incurs a loss, our operating results will reflect HEP’s loss,
net of intercompany eliminations, to the extent of our ownership interest in HEP at that point in time.
2012 Acquisition
UNEV Interest Transaction
On July 12, 2012, HEP acquired from us our 75% interest in UNEV. We received consideration consisting of $260.0 million in
cash and 1.0 million HEP common units. As a result of this transaction, our ownership interest in HEP increased to 44%, which
includes the 2% general partner interest. We have a 10-year transportation agreement with the UNEV Pipeline expiring in 2022
that results in minimum annualized payments to UNEV of $16.9 million.
We accounted for this transaction as a business transfer between entities under common control, whereby we have retrospectively
adjusted HEP financial information for all prior periods presented as if UNEV was a consolidated subsidiary of HEP since inception.
This had no impact on our consolidated balances and amounts; however, it did affect certain amounts presented under the HEP
segment in Note 21, “Segment Information” and Note 22, “Supplemental Guarantor/Non-Guarantor Financial Information.”
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2011 Acquisition
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Legacy Frontier Tankage and Terminal Asset Transaction
On November 9, 2011, HEP acquired from us certain tankage, loading rack and crude receiving assets located at our El Dorado
and Cheyenne Refineries. We received non-cash consideration consisting of promissory notes with an aggregate principal amount
of $150.0 million and 3.8 million HEP common units.
2010 Acquisitions
Tulsa East / Lovington Storage Asset Transaction
On March 31, 2010, HEP acquired from us certain storage assets for $93.0 million, consisting of hydrocarbon storage tanks having
approximately 2.0 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at our Tulsa East
facility and an asphalt loading rack facility located at our Navajo Refinery facility located in Lovington, New Mexico.
Transportation Agreements
HEP serves our refineries under long-term pipeline and terminal, tankage and throughput agreements expiring from 2019 through
2026. Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on
HEP's pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP including UNEV
(a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments
on July 1 at a rate based upon the percentage change in Producer Price Index (“PPI”) or Federal Energy Regulatory Commission
(“FERC”) index. As of December 31, 2012, these agreements result in minimum annualized payments to HEP of $217.2 million.
Since HEP is a consolidated VIE, our transactions with HEP including the acquisitions discussed above and fees paid under our
transportation agreements with HEP and UNEV are eliminated and have no impact on our consolidated financial statements.
HEP Common Unit Issuances
2012 Issuances
In July 2012, HEP issued 1.0 million of its common units to us as partial consideration for its purchase of our 75% interest in
UNEV.
2011 Issuances
In December 2011, HEP issued 1.5 million of its common units priced at $53.50 per unit. Aggregate net proceeds of $75.8 million
were used to repay a portion of the $150 million in promissory notes issued to us in connection with HEP's November 9, 2011
asset acquisition from us. This repayment to us is eliminated in our consolidated financial statements.
In November 2011, HEP issued 3.8 million of its common units to us as partial consideration for its purchase from us of certain
tankage, loading rack and crude receiving assets located at our El Dorado and Cheyenne Refineries.
As a result of these HEP common unit issuances, we adjusted additional capital, other comprehensive income and equity attributable
to HEP's noncontrolling interest holders to effectively reallocate a portion of HEP's equity among its unitholders.
NOTE 5:
Financial Instruments
Our financial instruments consist of cash and cash equivalents, investments in marketable securities, accounts receivable, accounts
payable, debt and derivative instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts
payable approximate fair value. HEP's outstanding credit agreement borrowings approximate fair value as interest rates are reset
frequently at current interest rates.
Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability,
including assumptions about risk). GAAP categorizes inputs used in fair value measurements into three broad levels as follows:
•
(Level 1) Quoted prices in active markets for identical assets or liabilities.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
•
•
(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and
liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable
market data.
(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value
of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.
The carrying amounts and estimated fair values of our investments in marketable securities, derivative instruments and the senior
notes at December 31, 2012 and December 31, 2011 were as follows:
Financial Instrument
December 31, 2012
Assets:
Marketable debt securities
Commodity price swaps
Total assets
Liabilities:
NYMEX futures contracts
Commodity price swaps
HollyFrontier senior notes
HEP senior notes
HEP interest rate swaps
Total liabilities
December 31, 2011
Assets:
Equity securities
Marketable debt securities
Commodity price swaps
Total assets
Liabilities:
NYMEX futures contracts
HollyFrontier senior notes
HEP senior notes
HEP interest rate swaps
Total liabilities
Carrying
Amount
Fair Value
Level 1
Level 2
Level 3
Fair Value by Input Level
(In thousands)
$
$
$
635,702
17,383
653,085
$
$
635,702
17,383
653,085
$
$
— $
635,702
—
— $
6,151
641,853
$
$
—
11,232
11,232
5,563
$
5,563
$
5,563
$
— $
83,982
435,254
443,673
3,430
83,982
470,990
484,125
3,430
—
—
—
—
39,092
470,990
484,125
3,430
—
44,890
—
—
—
$
971,902
$ 1,048,090
$
5,563
$
997,637
$
44,890
$
753
$
753
$
753
$
— $
260,953
175,654
260,953
175,654
—
—
260,953
144,038
$
437,360
$
437,360
$
753
$
404,991
$
$
1,252
$
1,252
$
1,252
$
— $
651,262
325,860
520
693,979
344,350
520
—
—
—
693,979
344,350
520
$
978,894
$ 1,040,101
$
1,252
$ 1,038,849
$
—
—
31,616
31,616
—
—
—
—
—
Level 1 Financial Instruments
Our investments in equity securities and our NYMEX futures contracts are exchange traded and are measured and recorded at fair
value using quoted market prices, a Level 1 input.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Level 2 Financial Instruments
Investments in marketable debt securities and derivative instruments consisting of commodity price swaps and HEP's interest rate
swaps are measured and recorded at fair value using Level 2 inputs. With respect to the commodity price and interest rate swap
contracts, fair value is based on the net present value of expected future cash flows related to both variable and fixed rate legs of
the respective swap agreements. The measurements are computed using market-based observable inputs, quoted forward
commodity prices with respect to our commodity price swaps and the forward London Interbank Offered Rate (“LIBOR”) yield
curve with respect to HEP's interest rate swaps. The fair value of the marketable debt securities and senior notes is based on values
provided by a third party, which were derived using market quotes for similar type instruments, a Level 2 input.
Level 3 Financial Instruments
We have commodity price swap contracts that relate to forecasted sales of diesel and unleaded gasoline and forecasted purchases
of WCS for which quoted forward market prices are not readily available. The forward rate used to value these price swaps was
derived using a projected forward rate using quoted market rates for similar products, adjusted for regional pricing and grade
differentials, a Level 3 input.
The following table presents the changes in fair value of our Level 3 assets and liabilities (all related to commodity price swap
contracts) for the year ended December 31, 2012:
Level 3 Financial Instruments
Asset balance at beginning of period
Change in fair value:
Recognized in other comprehensive income
Recognized in cost of products sold
Settlement date fair value of contractual maturities:
Recognized in sales and other revenues
Recognized in cost of products sold
Liability balance at end of period
Year Ended
December 31, 2012
(In thousands)
$
$
31,616
(120,966)
(39,463)
98,750
(3,595)
(33,658)
A hypothetical change of 10% to the estimated future cash flows attributable to our Level 3 commodity price swaps would result
in an estimated fair value change of approximately $5.4 million.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
NOTE 6: Earnings Per Share
Basic earnings per share is calculated as net income attributable to HollyFrontier stockholders divided by the average number of
shares of common stock outstanding. Diluted earnings per share assumes, when dilutive, the issuance of the net incremental shares
from variable restricted and variable performance shares. The following is a reconciliation of the denominators of the basic and
diluted per share computations for net income attributable to HollyFrontier stockholders:
2012
Years Ended December 31,
2011
(In thousands, except per share data)
2010
Earnings attributable to HollyFrontier stockholders
$
1,727,172
$
1,023,397
$
Average number of shares of common stock outstanding
Effect of dilutive variable restricted shares and performance
share units (1)
Average number of shares of common stock outstanding
assuming dilution
Basic earnings per share
Diluted earnings per share
205,289
158,486
103,964
106,436
895
808
782
206,184
159,294
107,218
$
$
8.41
8.38
$
$
6.46
6.42
$
$
0.98
0.97
—
(1) Excludes anti-dilutive restricted and performance share units of:
166
—
NOTE 7:
Stock-Based Compensation
As of December 31, 2012, we have two principal share-based compensation plans including the Frontier plan that was retained
upon the July 1, 2011 merger (collectively, the “Long-Term Incentive Compensation Plan”).
The compensation cost charged against income for these plans was $36.3 million, $24.7 million and $9.3 million for the years
ended December 31, 2012, 2011 and 2010, respectively. Our accounting policy for the recognition of compensation expense for
awards with pro-rata vesting (substantially all of our awards) is to expense the costs ratably over the vesting periods.
Additionally, HEP maintains a share-based compensation plan for HEP directors and select Holly Logistic Services, L.L.C.
executives and employees. Compensation cost attributable to HEP’s share-based compensation plan was $2.7 million, $2.1 million
and $2.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Restricted Stock
Under our Long-Term Incentive Compensation Plan, we grant certain officers, other key employees and non-employee directors
restricted stock awards with most awards vesting over a period of one to three years. Although ownership of the shares does not
transfer to the recipients until the shares vest, recipients generally have dividend rights on these shares from the date of grant. The
vesting for certain key executives is contingent upon certain performance targets being realized. The fair value of each share of
restricted stock awarded, including the shares issued to the key executives, is measured based on the market price as of the date
of grant and is amortized over the respective vesting period.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
A summary of restricted stock activity and changes during the year ended December 31, 2012 is presented below:
Restricted Stock
Outstanding at January 1, 2012 (non-vested)
Granted
Vesting and transfer of ownership to recipients
Forfeited
Outstanding at December 31, 2012 (non-vested)
Weighted
Average Grant
Date Fair
Value
Aggregate
Intrinsic Value
($000)
Grants
1,122,350
760,177
(1,035,025)
(3,975)
843,527
$
$
25.48
37.27
26.75
33.06
34.52
$
39,266
For the year ended December 31, 2012, we issued 1,035,025 shares of our common stock upon the vesting of restricted stock
grants having a grant date fair value of $27.7 million. As of December 31, 2012, there was $17.4 million of total unrecognized
compensation cost related to non-vested restricted stock grants. That cost is expected to be recognized over a weighted-average
period of 1.7 years.
Performance Share Units
Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees performance share units,
which are payable in stock upon meeting certain criteria over the service period, and generally vest over a period of three years.
Under the terms of our performance share unit grants, awards are subject to either a “financial performance” or “market
performance” criteria, or both.
The fair value of performance share unit awards subject to financial performance criteria is computed using the grant date closing
stock price of each respective award grant and will apply to the number of units ultimately awarded. The number of shares ultimately
issued for each award will be based on our financial performance as compared to peer group companies over the performance
period and can range from zero to 200%. As of December 31, 2012, estimated share payouts for outstanding non-vested performance
share unit awards ranged approximately from 110% to 180%.
For the performance share units subject to market performance criteria, performance is calculated as the total shareholder return
achieved by HollyFrontier stockholders compared with the average shareholder return achieved by an equally-weighted peer group
of independent refining companies over a three-year period. These share unit awards are valued using a Monte Carlo valuation
model, which simulates future stock price movements using key inputs including grant date stock prices, expected stock price
performance, expected rate of return and volatility. These units are payable in stock based on share price performance relative to
the defined peer group and can range from zero to 200% of the initial target award.
A summary of performance share unit activity and changes during the year ended December 31, 2012 is presented below:
Performance Share Units
Outstanding at January 1, 2012 (non-vested)
Granted
Vesting and transfer of ownership to recipients
Forfeited
Outstanding at December 31, 2012 (non-vested)
Grants
774,788
561,815
(452,357)
(8,672)
875,574
For the year ended December 31, 2012, we issued 869,231 shares of our common stock, representing a 192% payout on vested
performance share units having a grant date fair value of $6.0 million. Based on the weighted-average grant date fair value of
$35.38 per share, there was $26.7 million of total unrecognized compensation cost related to non-vested performance share units.
That cost is expected to be recognized over a weighted-average period of 1.8 years.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
NOTE 8: Cash and Cash Equivalents and Investments in Marketable Securities
Our investment portfolio at December 31, 2012 consisted of cash, cash equivalents and investments in marketable debt securities.
We invest in highly-rated marketable debt securities that have maturities at the date of purchase of greater than three months. We
also invest in other marketable debt securities with the maximum maturity or put date of any individual issue generally not greater
than two years from the date of purchase, which are usually held until maturity. All of these instruments are classified as available-
for-sale. As a result, they are reported at fair value using quoted market prices. Interest income is recorded as earned. Unrealized
gains and losses, net of related income taxes, are reported as a component of accumulated other comprehensive income. Upon sale
or maturity, realized gains on our marketable debt securities are recognized as interest income. These gains are computed based
on the specific identification of the underlying cost of the securities, net of unrealized gains and losses previously reported in other
comprehensive income.
The following is a summary of our available-for-sale securities:
December 31, 2012
Certificates of deposit
Commercial paper
Corporate debt securities
State and political subdivisions debt securities
Total marketable securities
December 31, 2011
State and political subdivisions debt securities
Equity securities
Total marketable securities
Amortized
Cost
Gross
Unrealized
Gain
Gross
Unrealized
Loss
Fair Value
(Net Carrying
Amount)
(In thousands)
$
$
$
$
82,791
45,737
49,587
457,615
635,730
260,879
610
261,489
$
$
$
$
14
17
2
26
59
74
143
217
$
$
$
$
(6) $
—
(30)
(51)
(87) $
— $
—
— $
82,799
45,754
49,559
457,590
635,702
260,953
753
261,706
For the years ended December 31, 2012 and 2011, we recognized $1.1 million and $0.4 million, respectively, of interest income
on our marketable debt securities. Unrealized gains and losses are temporary.
NOTE 9:
Inventories
Inventory consists of the following components:
Crude oil
Other raw materials and unfinished products(1)
Finished products(2)
Process chemicals(3)
Repairs and maintenance supplies and other
Total inventory
December 31,
2012
2011
(In thousands)
$
502,978
$
150,090
585,610
3,514
77,440
400,952
137,356
513,776
1,180
61,355
$
1,319,632
$
1,114,619
(1) Other raw materials and unfinished products include feedstocks and blendstocks, other than crude.
(2) Finished products include gasolines, jet fuels, diesels, lubricants, asphalts, LPG’s and residual fuels.
(3) Process chemicals include additives and other chemicals.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The excess of current cost over the LIFO value of inventory was $134.0 million and $378.0 million at December 31, 2012 and
2011, respectively. For the years ended December 31, 2012, 2011 and 2010, we recognized reductions of $4.2 million, $0.1 million
and $4.1 million, respectively, to cost of products sold as we liquidated certain LIFO inventory quantities carried at historical LIFO
acquisition costs below market value at the time of liquidation.
NOTE 10: Properties, Plants and Equipment
December 31,
2012
2011
(In thousands)
Land, buildings and improvements
$
198,610
$
Refining facilities
Pipelines and terminals
Transportation vehicles
Other fixed assets
Construction in progress
Accumulated depreciation
2,261,733
1,113,080
29,970
105,075
234,646
3,943,114
(748,414)
3,194,700
$
$
168,108
2,106,900
922,866
29,418
97,676
306,819
3,631,787
(578,882)
3,052,905
We capitalized interest attributable to construction projects of $9.1 million, $17.2 million and $7.2 million for the years ended
December 31, 2012, 2011 and 2010, respectively.
Depreciation expense was $182.9 million, $125.0 million and $94.0 million for the years ended December 31, 2012, 2011 and
2010, respectively. For the years ended December 31, 2012, 2011 and 2010, depreciation expense included $55.5 million, $31.2
million and $26.9 million, respectively, attributable to HEP operations.
NOTE 11: Goodwill
The following table provides a summary of changes to our goodwill balance by segment for the year ended December 31, 2012.
Balance at January 1, 2012
Adjustment to goodwill related to Frontier merger
Balance at December 31, 2012
Refining
Segment
$
$
2,047,519
1,792
2,049,311
HEP
(In thousands)
288,991
$
—
288,991
$
Total
$
$
2,336,510
1,792
2,338,302
During the first quarter of 2012, we adjusted goodwill upon finalizing certain fair value estimates that primarily relate to income
tax receivables, properties, plants and equipment and environmental liabilities that were recognized upon our July 1, 2011 merger
with Frontier.
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NOTE 12: Environmental
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
We expensed $46.1 million, $14.0 million and $(0.6) million for the years ended December 31, 2012, 2011 and 2010, respectively,
for environmental remediation obligations. In 2012, we increased certain environmental cost accruals to reflect revisions to certain
cost estimates and the timeframe for which certain environmental remediation and monitoring activities are expected to occur.
The accrued environmental liability reflected in our consolidated balance sheets was $88.9 million and $42.2 million at
December 31, 2012 and 2011, respectively, of which $72.6 million and $31.7 million, respectively, were classified as other long-
term liabilities. These accruals include remediation and monitoring costs expected to be incurred over an extended period of time
(up to 30 years for certain projects). They also include $15.6 million in environmental liabilities that were assumed upon our
merger with Frontier in 2011.
NOTE 13: Debt
HollyFrontier Credit Agreement
We have a $1 billion senior secured credit agreement (the “HollyFrontier Credit Agreement”) with Union Bank, N.A. as
administrative agent and certain lenders from time to time party thereto. The HollyFrontier Credit Agreement matures in July 2016
and may be used to fund working capital requirements, capital expenditures, acquisitions and general corporate purposes.
Obligations under the HollyFrontier Credit Agreement are collateralized by our inventory, accounts receivables and certain deposit
accounts and guaranteed by our material, wholly-owned subsidiaries. At December 31, 2012, we were in compliance with all
covenants, had no outstanding borrowings and had outstanding letters of credit totaling $29.2 million under the HollyFrontier
Credit Agreement.
HEP Credit Agreement
HEP has a $550 million senior secured revolving credit facility that matures in June 2017 (the “HEP Credit Agreement”) and is
available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general
partnership purposes. It is also available to fund letters of credit up to a $50 million sub-limit and to fund distributions to unitholders
up to a $60 million sub-limit. At December 31, 2012, HEP was in compliance with all its covenants, had outstanding borrowings
of $421.0 million and no outstanding letters of credit under the HEP Credit Agreement.
HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically
in our consolidated balance sheets). Indebtedness under the HEP Credit Agreement involves recourse to HEP Logistics Holdings,
L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be
limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s
creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated
subsidiaries.
HollyFrontier Senior Notes
Our senior notes consist of the following:
•
•
9.875% senior notes ($286.8 million principal amount maturing June 2017)
6.875% senior notes ($150 million principal amount maturing November 2018)
These senior notes (collectively, the “HollyFrontier Senior Notes”) are unsecured and impose certain restrictive covenants, including
limitations on our ability to incur additional debt, incur liens, enter into sale-and-leaseback transactions, pay dividends, enter into
mergers, sell assets and enter into certain transactions with affiliates. At any time when the HollyFrontier Senior Notes are rated
investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, we will not be subject to many
of the foregoing covenants. Additionally, we have certain redemption rights under the HollyFrontier Senior Notes.
In September 2012, we redeemed our $200 million aggregate principal amount of 8.5% senior notes maturing September 2016 at
a redemption price of $208.5 million.
HollyFrontier Financing Obligation
We have a financing obligation that relates to a sale and lease-back of certain crude oil tankage that we sold to an affiliate of Plains
All American Pipeline, L.P. (“Plains”) in October 2009 for $40.0 million. Monthly lease payments are recorded as a reduction in
principal over the 15-year lease term ending in 2024.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
HEP Senior Notes
HEP’s senior notes consist of the following:
•
•
8.25% HEP senior notes ($150 million principal amount maturing March 2018)
6.5% HEP senior notes ($300 million principal amount maturing March 2020)
In March 2012, HEP issued $300 million in an aggregate principal amount of 6.5% HEP senior notes maturing March 2020. The
$294.8 million in net proceeds were used to repay $157.8 million aggregate principal amount of 6.25% HEP senior notes, $72.9
million in promissory notes due to HollyFrontier, related fees, expenses and accrued interest in connection with these transactions
and to repay borrowings under the HEP Credit Agreement. In April 2012, HEP called for redemption the remaining $27.2 million
aggregate principal amount outstanding of 6.25% HEP senior notes.
The 8.25% and 6.5% HEP senior notes (collectively, the “HEP Senior Notes”) are unsecured and impose certain restrictive
covenants, including limitations on HEP’s 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 HEP Senior Notes are
rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject
to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes.
Indebtedness under the HEP Senior Notes involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed
by HEP’s wholly-owned subsidiaries. However, any recourse to the general partner would be limited to the extent of HEP Logistics
Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no other recourse to our
assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.
The carrying amounts of long-term debt are as follows:
9.875% Senior Notes
Principal
Unamortized discount
6.875% Senior Notes
Principal
Unamortized premium
8.5% Senior Notes
Principal
Unamortized premium
Financing Obligation
Total HollyFrontier long-term debt
December 31,
2012
2011
(In thousands)
$
$
286,812
(7,468)
279,344
150,000
5,910
155,910
—
—
—
36,311
471,565
291,812
(8,930)
282,882
150,000
6,490
156,490
199,985
11,905
211,890
37,620
688,882
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
December 31,
2012
2011
(In thousands)
421,000
200,000
150,000
(1,602)
148,398
300,000
(4,725)
295,275
—
—
—
—
864,673
150,000
(1,907)
148,093
—
—
—
185,000
(8,331)
1,098
177,767
525,860
$
1,336,238
$
1,214,742
HEP Credit Agreement
HEP 8.25% Senior Notes
Principal
Unamortized discount
HEP 6.5% Senior Notes
Principal
Unamortized discount
HEP 6.25% Senior Notes
Principal
Unamortized discount
Unamortized premium – designated fair value hedge
Total HEP long-term debt
Total long-term debt
Principal maturities of long-term debt are as follows:
Years Ending December 31,
(In thousands)
2013
2014
2015
2016
2017
Thereafter
Total
$
1,477
1,666
1,880
2,121
710,205
626,774
$
1,344,123
NOTE 14: Derivative Instruments and Hedging Activities
Commodity Price Risk Management
Our primary market risk is commodity price risk. We are exposed to market risks related to the volatility in crude oil and refined
products, as well as volatility in the price of natural gas used in our refining operations. We periodically enter into derivative
contracts in the form of commodity price swaps and futures contracts to mitigate price exposure with respect to:
•
•
•
•
•
our inventory positions;
natural gas purchases;
costs of crude oil and related grade differentials;
prices of refined products; and
our refining margins.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Accounting Hedges
We have swap contracts serving as cash flow hedges against price risk on forecasted purchases of natural gas and WTI crude oil
and forecasted sales of ultra-low sulfur diesel and conventional unleaded gasoline. These contracts have been designated as
accounting hedges and are measured quarterly at fair value with offsetting adjustments (gains/losses) recorded directly to other
comprehensive income. These fair value adjustments are later reclassified to earnings as the hedging instruments mature. Also on
a quarterly basis, hedge ineffectiveness is measured by comparing the change in fair value of the swap contracts against the expected
future cash inflows/outflows on the respective transaction being hedged. Any hedge ineffectiveness is also recognized in earnings.
The following table presents the pre-tax effect on other comprehensive income (“OCI”) and earnings due to fair value adjustments
and maturities of commodity price swaps under hedge accounting:
Unrealized
Gain (Loss)
Recognized in
OCI
Gain (Loss) Recognized in
Earnings Due to Settlements
Amount
Location
Gain (Loss) Attributable to
Hedge Ineffectiveness
Recognized in Earnings
Location
Amount
Year Ended December 31, 2012
Commodity price swaps
Change in fair value
Loss reclassified to earnings due to
settlements
Total
Year Ended December 31, 2011
Commodity price swaps
Change in fair value
Loss reclassified to earnings due to
settlements
Total
Year Ended December 31, 2010
Commodity price swaps
Change in fair value
Loss reclassified to earnings due to
settlements
Total
$
$
$
$
$
$
Sales and other
revenues
Cost of
products sold
(248,399)
55,175
(193,224)
173,208
166
173,374
Operating
expenses
(1,402)
1,364
(38)
Operating
expenses
$
$
$
$
$
$
(In thousands)
Sales and other
revenues
Cost of
products sold
(98,750)
43,575
(55,175)
Cost of
products sold
(166)
(166)
(1,364)
(1,364)
$
$
$
$
$
$
(491)
(515)
(1,006)
446
446
—
—
As of December 31, 2012, we have the following notional contract volumes related to outstanding swap contracts serving as cash
flow hedges against price risk on forecasted purchases of natural gas and crude oil and sales of refined products:
Commodity Price Swaps
Natural gas - long
WTI crude oil - long
Notional Contract Volumes by Year of Maturity
Total
Outstanding
Notional
2013
2014
2015
2016
2017
Unit of
Measure
96,000,000
19,200,000
19,200,000
19,200,000
19,200,000
19,200,000 MMBTU
Ultra-low sulfur diesel - short
11,490,000
11,125,000
Unleaded gasoline - short
1,440,000
1,440,000
12,930,000
12,565,000
365,000
365,000
—
—
—
—
—
—
—
— Barrels
— Barrels
— Barrels
Economic Hedges
We also have swap contracts that serve as economic hedges (derivatives used for risk management, but not designated as accounting
hedges) to fix our purchase price on forecasted crude oil and other feedstock purchases, and to lock in the spread between WCS
and WTI crude oil on forecasted WCS purchases. Also, we have NYMEX futures contracts to lock in prices on purchases of
inventory. These contracts are measured quarterly at fair value with offsetting adjustments (gains/losses) recorded directly to
income.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The following table presents the pre-tax effect on income due to maturities and fair value adjustments of our economic hedges:
Location of Gain Recognized in Income
2012
Years Ended December 31,
2011
(In thousands)
2010
Cost of products sold
Operating expenses
Total
$
$
12,295
573
12,868
$
$
3,219
—
3,219
$
$
317
—
317
As of December 31, 2012, we have the following notional contract volumes related to our outstanding derivative contracts serving
as economic hedges, all maturing in 2013:
Derivative Instrument
Total
Outstanding
Notional
Unit of Measure
Commodity price swap (WCS spread) - long
6,022,500
Barrels
Commodity price swap (WTI) - short
Commodity price swap (gasoline) - short
NYMEX futures (WTI) - long
NYMEX futures (WTI) - short
Physical contracts - long
Physical contracts - short
150,000
Barrels
192,000
Barrels
234,000
Barrels
1,091,000
Barrels
540,000
Barrels
540,000
Barrels
Interest Rate Risk Management
HEP uses interest rate swaps to manage its exposure to interest rate risk.
As of December 31, 2012, HEP had three interest rate swap contracts that hedge its exposure to the cash flow risk caused by the
effects of LIBOR changes on $305.0 million in credit agreement advances. The first interest rate swap effectively converts $155.0
million of LIBOR based debt to fixed rate debt having an interest rate of 0.99% plus an applicable margin of 2.25% as of
December 31, 2012, which equaled an effective interest rate of 3.24%. This swap matures in February 2016. HEP has two additional
interest rate swaps with identical terms which effectively convert $150.0 million of LIBOR based debt to fixed rate debt having
an interest rate of 0.74% plus an applicable margin of 2.25% as of December 31, 2012, which equaled an effective interest rate of
2.99%. Both of these swap contracts mature in July 2017. All of these swap contracts have been designated as cash flow hedges.
To date, there has been no ineffectiveness on these cash flow hedges.
At December 31, 2012, HEP had a pre-tax unrealized loss recorded in accumulated other comprehensive income of $4.3 million
that relates to its current and previous cash flow hedging instruments. Of this amount, $0.8 million relates to a cash flow hedge
terminated in December 2011 and represents the application of hedge accounting prior to termination. This amount will be amortized
as a charge to interest expense through February 2013, the remaining term of the terminated swap contract.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The following table presents the pre-tax effect on other comprehensive income and earnings due to fair value adjustments and
maturities of HEP's interest rate swaps under cash flow hedge accounting:
Unrealized
Gain (Loss)
Recognized in
OCI
Loss Recognized in Earnings Due
to Settlements
Location
(In thousands)
Amount
Year Ended December 31, 2012
Interest rate swaps
Change in fair value
Loss reclassified to earnings due to
settlements
Total
Year Ended December 31, 2011
Interest rate swaps
Change in fair value
Loss reclassified to earnings due to
settlements
Total
Year Ended December 31, 2010
Interest rate swaps
Change in fair value
Loss reclassified to earnings due to
settlements
Total
$
$
$
$
$
$
(4,418)
6,603
2,185
(1,915)
5,477
3,562
(7,596)
6,711
(885)
Interest expense
Interest expense
Interest expense
$
$
$
$
$
$
(6,603)
(6,603)
(5,477)
(5,477)
(6,711)
(6,711)
The following table presents balance sheet locations and fair values of our outstanding derivative instruments. These amounts are
presented on a gross basis and do not reflect the netting of asset or liability positions permitted under the terms of master netting
arrangements. Therefore, they are not equal to amounts presented in our consolidated balance sheets.
Asset Derivatives
Liability Derivatives
Balance Sheet
Location
Fair Value
Balance Sheet
Location
Fair Value
(In thousands)
December 31, 2012
Derivatives designated as cash flow hedging instruments:
Commodity price swap contracts
Accrued liabilities
Variable-to-fixed interest rate swap
contracts
Total
Derivatives not designated as hedging instruments:
Commodity price swap contracts
Total
$
$
17,383 Accrued liabilities
Other long-term liabilities
Other long-term liabilities
17,383
Accrued liabilities
$
$
$
$
28,054
9,774
3,430
41,258
51,717
51,717
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Asset Derivatives
Liability Derivatives
Balance Sheet
Location
Fair Value
Balance Sheet
Location
Fair Value
(In thousands)
December 31, 2011
Derivatives designated as cash flow hedging instruments:
Commodity price swap contracts
Prepayments and other
current assets
Variable-to-fixed interest rate swap
contracts
Total
Derivatives not designated as hedging instruments:
Commodity price swap contracts
Prepayments and other
current assets
$
$
$
173,784
173,784
Other long-term liabilities
1,870 Accrued liabilities
$
$
$
520
520
1,252
At December 31, 2012, we had a pre-tax net unrealized loss of $23.3 million classified in accumulated other comprehensive income
that relates to all accounting hedges. Assuming commodity prices and interest rates remain unchanged, an unrealized loss of
approximately $11.7 million will be effectively transferred from accumulated other comprehensive income into the statement of
income as the hedging instruments mature over the next twelve-month period.
NOTE 15: Income Taxes
The provision for income taxes is comprised of the following:
Current
Federal
State
Deferred
Federal
State
2012
Years Ended December 31,
2011
(In thousands)
2010
$
$
797,406
135,148
70,671
24,737
1,027,962
$
$
499,535
91,316
(9,679)
819
581,991
$
$
30,999
4,473
21,796
2,044
59,312
The statutory federal income tax rate applied to pre-tax book income reconciles to income tax expense as follows:
Tax computed at statutory rate
State income taxes, net of federal tax benefit
Domestic production activities deduction
Noncontrolling interest in net income
Uncertain tax positions
Other
2012
Years Ended December 31,
2011
(In thousands)
2010
$
$
975,798
110,739
(54,745)
(12,783)
7,309
1,644
1,027,962
$
$
574,682
64,284
(32,194)
(14,221)
(12,125)
1,565
581,991
$
$
67,327
4,372
(940)
(11,315)
—
(132)
59,312
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities
for financial reporting purposes and the amounts used for income tax purposes. Our deferred income tax assets and liabilities as
of December 31, 2012 and 2011 are as follows:
Deferred income taxes
Accrued employee benefits
Accrued post-retirement benefits
Accrued environmental costs
Hedging instruments
Inventory differences
Prepayments and other
Total current
Properties, plants and equipment (due primarily to
tax in excess of book depreciation)
Accrued post-retirement benefits
Accrued environmental costs
Hedging instruments
Deferred turnaround costs
Net operating loss and tax credit carryforwards
Investment in HEP
Debt fair value premiums
Contingent liabilities
Other
Total noncurrent
Total
Deferred income taxes
Accrued employee benefits
Accrued post-retirement benefits
Accrued environmental costs
Inventory differences
Deferred turnaround costs
Prepayments and other
Total current
Properties, plants and equipment (due primarily to
tax in excess of book depreciation)
Accrued post-retirement benefits
Accrued environmental costs
Deferred turnaround costs
Investment in HEP
Other
Total noncurrent
Total
$
$
$
$
Assets
December 31, 2012
Liabilities
(In thousands)
Total
13,285
—
5,096
23,927
—
—
42,308
—
15,628
18,963
3,802
—
21,863
—
8,820
2,908
6,766
78,750
121,058
$
— $
(563)
—
—
(181,634)
(5,327)
(187,524)
(539,338)
—
—
—
(60,167)
—
(15,915)
—
—
—
(615,420)
(802,944) $
$
13,285
(563)
5,096
23,927
(181,634)
(5,327)
(145,216)
(539,338)
15,628
18,963
3,802
(60,167)
21,863
(15,915)
8,820
2,908
6,766
(536,670)
(681,886)
Assets
December 31, 2011
Liabilities
(In thousands)
Total
— $
—
—
(161,428)
(356)
(80,397)
(242,181)
(511,788)
—
—
(22,971)
(13,389)
(4,715)
(552,863)
(795,044) $
22,791
4,012
2,253
(161,428)
(356)
(42,955)
(175,683)
(511,788)
41,873
4,651
(22,971)
(13,389)
37,903
(463,721)
(639,404)
22,791
4,012
2,253
—
—
37,442
66,498
—
41,873
4,651
—
—
42,618
89,142
155,640
$
$
83
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
At December 31, 2012, we had a net operating loss carryforward of $46.5 million in the state of Colorado that is scheduled to be
utilized in 2013 through 2029 and a Kansas income tax credit of $15.8 million that is scheduled to be utilized in 2013 through
2019. These amounts are reflected in other current and non-current deferred tax assets.
As of December 31, 2012, the total amount of unrecognized tax benefits was $12.6 million. A reconciliation of the beginning and
ending amount of unrecognized tax benefits is as follows:
Balance at January 1
Additions due to merger with Frontier
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements
Reductions for statute limitations
Balance at December 31
$
$
2012
$
$
Years Ended December 31,
2011
(In thousands)
1,864
22,577
73
(204)
(21,679)
(206)
2,425
2,425
—
10,305
(89)
—
—
12,641
$
$
2010
1,964
—
6
(106)
—
—
1,864
At December 31, 2012, 2011 and 2010, there are $10.2 million, $2.2 million and $1.1 million, respectively, of unrecognized tax
benefits that, if recognized, would affect our effective tax rate. Unrecognized tax benefits are adjusted in the period in which new
information about a tax position becomes available or the final outcome differs from the amount recorded.
We recognize interest and penalties relating to liabilities for unrecognized tax benefits as an element of tax expense. We have not
recorded any penalties related to our uncertain tax positions as we believe that it is more likely than not that there will not be any
assessment of penalties. We expect that unrecognized tax benefits for tax positions taken with respect to 2012 and prior years will
change within the next 12 months and the majority of these items will be settled with taxing authorities.
We are subject to U.S. federal income tax, Oklahoma, New Mexico, Kansas, Utah, Arizona, Colorado and Iowa income tax and
to income tax of multiple other state jurisdictions. We have substantially concluded all U.S. federal, state and local income tax
matters for tax years through December 31, 2005. In late 2010, the Internal Revenue Service commenced an examination of our
U.S. federal tax returns for tax years ended December 31, 2006, 2007, 2008 and 2009. We anticipate that these audits will be
completed in 2013.
NOTE 16: Stockholders' Equity
Shares of our common stock outstanding and activity for the years ended December 31, 2012, 2011 and 2010 are presented below:
Common shares outstanding at January 1
Common shares issued in connection with merger with Frontier
Issuance of common shares upon exercise of stock options
Issuance of restricted stock, excluding restricted stock with
performance feature
Vesting of performance units
Vesting of restricted stock with performance feature
Forfeitures of restricted stock
Purchase of treasury stock (1)
Common shares outstanding at December 31
2012
Years Ended December 31,
2011
(In thousands)
2010
209,332,646
—
—
691,207
869,231
146,400
(3,975)
(7,484,013)
203,551,496
106,529,376
103,270,002
—
106,132,538
—
80,400
512,880
233,134
124,332
(3,730)
(1,333,348)
209,332,646
282,886
140,286
12,300
(30,084)
(88,950)
106,529,376
(1) Includes 560,484, 747,225 and 88,950 shares, respectively, withheld under the terms of stock-based compensation agreements to
provide funds for the payment of payroll and income taxes due at the vesting of share-based awards.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
In January 2012, our Board of Directors approved a $350 million stock repurchase program, and in June 2012, approved an
additional $350 million repurchase program that authorizes us to repurchase common stock in the open market or through privately
negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and
other relevant considerations. These programs may be discontinued at any time by the Board of Directors. As of December 31,
2012, we have repurchased 6,775,729 shares at a cost of $205.6 million under these stock repurchase programs.
In May 2012, we entered into a structured share repurchase arrangement with a financial institution under which we provided an
up-front cash payment of $100.0 million and, depending on market conditions, would either receive shares of our common stock
or cash at the expiration of the agreement. The agreement expired in September 2012 at which time we received our up-front
payment plus an additional $8.6 million in cash that was recorded as additional capital.
During the years ended December 31, 2012, 2011 and 2010, we withheld shares of our common stock from certain employees in
the amounts of $22.4 million, $24.9 million and $1.2 million, respectively. These withholdings were made under the terms of
restricted stock and performance share unit agreements, and we concurrently made cash payments to fund payroll and income
taxes due at the vesting of restricted and performance shares in the case of officers and employees who elected to have shares
withheld from vested amounts to pay such taxes. The amounts withheld in 2011 also reflect withholdings associated with “change
in control” instant vesting provisions of the legacy Frontier stock awards.
NOTE 17: Other Comprehensive Income (Loss)
The components and allocated tax effects of other comprehensive income (loss) are as follows:
Year Ended December 31, 2012
Unrealized loss, net of reclassifications from sale or maturity, on available-for-
sale securities
Unrealized loss on hedging activities
Pension plan curtailment
Change in minimum pension liability
Retirement medical plan amendment
Other comprehensive loss
Less other comprehensive income attributable to noncontrolling interest
Other comprehensive loss attributable to HollyFrontier stockholders
Year Ended December 31, 2011
Unrealized loss on available-for-sale securities
Unrealized gain on hedging activities
Change in minimum pension liability
Change in retirement medical obligation
Other comprehensive income
Less other comprehensive income attributable to noncontrolling interest
Other comprehensive income attributable to HollyFrontier stockholders
Year Ended December 31, 2010
Unrealized gain on available-for-sale securities
Unrealized loss on hedging activities
Change in minimum pension liability
Change in retirement medical obligation
Other comprehensive loss
Less other comprehensive loss attributable to noncontrolling interest
Other comprehensive loss attributable to HollyFrontier stockholders
Before-Tax
Tax Expense
(Benefit)
(In thousands)
After-Tax
$
$
$
$
$
$
(236) $
(191,039)
7,102
(9,161)
53,450
(139,884)
1,364
(141,248) $
(95) $
(74,846)
2,763
(3,564)
20,792
(54,950)
—
(54,950) $
(516) $
(199) $
176,936
(71)
(3,515)
172,834
2,815
170,019
114
(923)
(1,470)
(238)
(2,517)
(1,623)
$
$
(894) $
67,732
(28)
(1,367)
66,138
—
66,138
$
$
42
275
(572)
(93)
(348)
—
(348) $
(141)
(116,193)
4,339
(5,597)
32,658
(84,934)
1,364
(86,298)
(317)
109,204
(43)
(2,148)
106,696
2,815
103,881
72
(1,198)
(898)
(145)
(2,169)
(1,623)
(546)
The temporary unrealized gain (loss) on available-for-sale securities is due to changes in market prices of securities.
85
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Accumulated other comprehensive income (loss) in the equity section of our consolidated balance sheets includes:
Pension obligation
Retirement medical obligation
Unrealized gain (loss) on available-for-sale securities
Unrealized gain (loss) on hedging instruments, net of noncontrolling interest
Accumulated other comprehensive income (loss)
$
$
(23,973) $
28,605
(7)
(13,050)
(8,425) $
(22,715)
(4,042)
134
104,496
77,873
December 31,
2012
2011
(In thousands)
NOTE 18: Retirement Plan
We sponsor a non-contributory defined benefit retirement plan that covers most legacy Holly non-union employees hired prior to
January 1, 2007 and union employees hired prior to July 1, 2010, and was closed to new entrants effective January 1, 2007 for
non-union employees and July 1, 2010 for union employees. Effective January 1, 2012, we ceased to accrue additional benefits
under this plan for non-union employee participants, and effective May 1, 2012, we ceased to accrue additional benefits for union
employee participants, at which time the plan was fully frozen. The changes for union employee participants have been accounted
for as a curtailment. Accordingly, we adjusted the projected benefit obligation and accumulated other comprehensive income by
$7.1 million and recorded additional pension expense of $0.7 million in the second quarter of 2012. The changes related to the
non-union employees were also accounted for as a curtailment, which was recorded in the fourth quarter of 2011. Our funding
policy for this defined benefit retirement plan is to make annual contributions of not less than the minimum funding requirements
of the Employee Retirement Income Security Act of 1974. Benefits are based on the employee’s years of service and compensation.
In 2012, our Compensation Committee, pursuant to authority delegated to it by the Board of Directors, approved the termination
of the HollyFrontier Corporation Pension Plan (the “Plan”). Accordingly, our remaining liability under the Plan is expected to be
funded in 2013. Our actual obligations under the Plan are contingent upon the timing of the pension plan termination as well as
participant settlement obligations. We expect to record an additional expense on termination of the Plan at the date we are released
from the liability, including the amount of actuarial loss currently recorded as accumulated other comprehensive income ($37.6
million, $23.0 million after-tax) at December 31, 2012 plus an amount equal to any contribution we make to the Plan in excess of
the $17.7 million accrued pension liability we have recorded at December 31, 2012.
The following table sets forth the changes in the benefit obligation and plan assets of our retirement plan for the years ended
December 31, 2012 and 2011:
Change in plan's benefit obligation
Pension plan's benefit obligation - beginning of year
Service cost
Interest cost
Benefits paid
Actuarial loss
Settlements paid
Curtailment
Pension plan's benefit obligation - end of year
Years Ended December 31,
2012
2011
(In thousands)
93,378
679
3,962
(1,379)
13,203
(7,256)
(7,102)
95,485
$
$
94,083
5,070
5,125
(1,347)
16,108
(10,510)
(15,151)
93,378
$
$
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Change in pension plan assets
Fair value of plan assets - beginning of year
Actual return on plan assets
Benefits paid
Employer contributions
Settlements paid
Fair value of plan assets - end of year
Funded status
Under-funded balance
Amounts recognized in consolidated balance sheets
Accrued pension liability
Amounts recognized in accumulated other comprehensive loss
Cumulative actuarial loss
Prior service cost
Total
Years Ended December 31,
2012
2011
(In thousands)
$
$
$
$
$
$
61,398
2,615
(1,379)
22,379
(7,256)
77,757
$
$
64,490
(1,235)
(1,347)
10,000
(10,510)
61,398
(17,728) $
(31,980)
(17,728) $
(31,980)
(37,589) $
—
(37,589) $
(35,094)
(966)
(36,060)
The accumulated benefit obligation was $95.5 million and $86.1 million at December 31, 2012 and 2011, respectively. The
measurement dates used for our retirement plan were December 31, 2012 and 2011.
The weighted average assumptions used to determine end of period benefit obligations:
December 31,
2012
2011
Discount rate
Rate of future compensation increases
3.95%
N/A
4.60%
4.00%
Net periodic pension expense consisted of the following components:
2012
2010
$
Years Ended December 31,
2011
(In thousands)
5,070
$
5,125
(5,230)
390
2,126
3,951
1,065
12,497
679
3,962
(3,798)
67
1,933
2,855
899
6,597
$
$
4,595
5,154
(4,576)
390
2,196
—
—
7,759
Service cost – benefit earned during the year
Interest cost on projected benefit obligations
Expected return on plan assets
Amortization of prior service cost
Amortization of net loss
Effect of settlements
Effect of curtailment
Net periodic pension expense
$
$
87
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The weighted average assumptions used to determine net periodic benefit expense:
2012
December 31,
2011
2010
Discount rate
Rate of future compensation increases
Expected long-term rate of return on assets
4.60%
4.00%
6.50%
5.65%
4.00%
8.00%
6.20%
4.00%
8.50%
The estimated amounts that will be amortized from accumulated other comprehensive income into net periodic benefit expense
in 2013 are as follows:
Actuarial loss
Prior service cost
Total
(In thousands)
$
$
2,771
—
2,771
At year end, our retirement plan assets were allocated as follows:
Asset Category
Cash and cash equivalents
Debt securities
Equity securities
Alternative investments
Total
Target
Allocation
2013
Percentage of Plan Assets at
December31,
2012
2011
100%
—%
—%
—%
100%
93%
—%
—%
7%
100%
—%
62%
30%
8%
100%
The investment policy developed for the Plan has been designed exclusively for the purpose of providing the highest probabilities
of delivering benefits to Plan members and beneficiaries. Among the factors considered in developing the investment policy are:
the Plan’s primary investment goal, rate of return objective, investment risk, investment time horizon, role of asset classes and
asset allocation. Due to the expected termination of the Plan, the current target asset allocation is 100% cash and cash equivalents.
The overall expected long-term rate of return on Plan assets at December 31, 2012 is 0.25% and is based on estimated returns for
cash and cash equivalents, a Level 1 input. See Note 5, Financial Instruments, for information on Level inputs.
In 2012, we established a program for plan participants whose benefits pursuant to the defined benefit plan were frozen. The
program provides for payments after year-end for each of the next three years provided the employee remains with us. The payments
are based on each employee's years of service and eligible salary. For the year ended December 31, 2012, we recognized transition
benefit costs of $15.6 million associated with transition to the new defined contribution plan.
Retirement Restoration Plan
We adopted an unfunded retirement restoration plan that provides for additional payments from us so that total retirement plan
benefits for certain executives will be maintained at the levels provided in the retirement plan before the application of Internal
Revenue Code limitations. Effective January 1, 2012, we ceased to accrue benefits under this plan. We expensed $0.3 million,
$0.6 million and $0.6 million for the years ended December 31, 2012, 2011 and 2010, respectively, in connection with this plan.
The accrued liability reflected in the consolidated balance sheets was $7.4 million and $6.7 million at December 31, 2012 and
2011, respectively. As of December 31, 2012, the projected benefit obligation under this plan was $7.4 million. Benefit payments,
which reflect expected future service, are expected to be paid as follows: $0.7 million in 2013; $2.2 million in 2014; $0.5 million
in 2015; $0.5 million in 2016; $1.5 million in 2017; and $1.4 million in 2018 through 2022.
Defined Contribution Plans
We have defined contribution “401(k)” plans that cover substantially all employees. Our contributions are based on employee's
compensation and partially match employee contributions. We expensed $16.0 million, $9.7 million and $5.5 million for the years
ended December 31, 2012, 2011 and 2010, respectively, in connection with these plans.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Post-retirement Healthcare Plans
We provide post-retirement medical benefits to certain eligible employees. These plans are unfunded and provide differing levels
of healthcare benefits dependent upon hire date and work location. Not all of our employees are covered by these plans at
December 31, 2012.
Effective December 31, 2012, we amended the post-retirement healthcare plans for participants retiring after December 31, 2012
by eliminating post-retirement benefits after reaching age 65 and eliminating early retirement benefits for most participants who
retire before reaching age 62. In addition, certain future retirees will receive a cash payment in lieu of post-retirement benefits
after reaching age 65 and other changes were made generally to conform benefits. We expect to pay $8.3 million during 2013 to
participants meeting certain requirements to receive a retiree medical transition payment.
The following table sets forth the changes in the benefit obligation and plan assets of our post-retirement healthcare plans for the
years ended December 31, 2012 and 2011:
Change in plans' benefit obligation
Post-retirement plans' benefit obligation - beginning of year
Service cost
Interest cost
Participant contributions
Amendments
Plan benefits paid
Plan combinations
Actuarial (gain) loss
Post-retirement plans' benefit obligation - end of year
Change in plan assets
Fair value of plan assets - beginning of year
Employer contributions
Participant contributions
Benefits paid
Fair value of plan assets - end of year
Funded status
Under-funded balance
Amounts recognized in consolidated balance sheets
Accrued post-retirement liability
Amounts recognized in accumulated other comprehensive loss
Actuarial loss
Transition obligation
Prior service cost
Total
$
$
$
$
$
$
$
$
Years Ended December 31,
2012
2011
(In thousands)
77,303
1,892
3,519
760
(49,399)
(1,275)
—
(6,003)
26,797
$
$
— $
515
760
(1,275) $
— $
7,862
1,569
2,193
460
(5,387)
(1,105)
62,632
9,079
77,303
—
645
460
(1,105)
—
(26,797) $
(77,303)
(26,797) $
(77,303)
$
5,359
—
(52,174)
(46,815) $
11,631
—
(4,997)
6,634
The accumulated benefit obligation was $26.8 million and $77.3 million at December 31, 2012 and 2011, respectively. The
measurement dates used for our post-retirement healthcare plans were December 31, 2012 and 2011. Benefit payments, which
reflect expected future service, are expected to be paid as follows: $9.7 million in 2013; $1.4 million in 2014; $1.3 million in 2015;
$1.3 million in 2016; $1.3 million in 2017; and $7.5 million in 2018 through 2022.
89
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The weighted average assumptions used to determine end of period benefit obligations:
Discount rate
Current health care trend rate
Ultimate health care trend rate
Year rate reaches ultimate trend rate
December 31,
2012
2011
3.45%
8.10%
5.00%
2023
4.60%
8.40%
5.00%
2023
Net periodic post-retirement expense consisted of the following components:
Service cost – benefit earned during the year
Interest cost on projected benefit obligations
Amortization of transition obligation
Amortization of prior service cost (credit)
Amortization of net loss
Net periodic pension expense
$
$
2010
2012
Years Ended December 31,
2011
(In thousands)
1,569
$
2,193
44
—
114
3,920
1,892
3,519
—
(2,221)
269
3,459
$
$
$
926
351
44
—
98
1,419
Assumed health care cost trend rates have an effect on the amounts reported for the post-retirement health care benefit plans. The
weighted average assumptions used to determine net periodic benefit expense follow:
2012
Years Ended December 31,
2011
2010
Discount rate
Current health care trend rate
Ultimate health care trend rate
Year rate reaches ultimate trend rate
4.60%
8.40%
5.00%
5.75%
8.70%
5.00%
2023
5.50%
9.00%
5.00%
2023
The effect of a 1% change in health care cost trend rates is as follows:
Service cost
Interest cost
Year-end accumulated post-retirement benefit obligation
$
$
$
1% Point
Increase
1% Point
Decrease
(In thousands)
506
778
1,745
$
$
$
(377)
(548)
(1,461)
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
NOTE 19: Lease Commitments
We lease certain office and storage facilities, railcars and other equipment under long-term operating leases, most of which contain
renewal options. At December 31, 2012, the minimum future rental commitments under operating leases having non-cancellable
lease terms in excess of one year are as follows:
2013
2014
2015
2016
2017
Thereafter
Total
(In thousands)
$
29,228
27,119
20,044
16,345
11,754
9,765
114,255
$
Rental expense charged to operations was $42.6 million, $35.9 million and $22.5 million for the years ended December 31, 2012,
2011 and 2010, respectively. For the years ended December 31, 2012, 2011 and 2010, rental expense included $8.1 million, $7.4
million and $7.1 million attributable to the HEP operations.
NOTE 20: Contingencies and Contractual Commitments
We are a party to various litigation and legal proceedings which we believe, based on advice of counsel, will not either individually
or in the aggregate have a materially adverse effect on our financial condition, results of operations or cash flows.
Contractual Commitments
We have various long-term agreements (entered in the normal course of business) to purchase crude oil, natural gas, feedstocks
and other resources to ensure we have adequate supplies to operate our refineries. The substantial majority of our purchase
obligations are based on market prices or rates. These contracts expire in 2014 through 2024.
We also have long-term agreements with third parties for the transportation and storage of crude oil, natural gas and feedstocks
to our refineries and for terminal and storage services that expire in 2013 through 2024. At December 31, 2012, the minimum
future transportation and storage fees under transportation agreements having terms in excess of one year are as follows:
2013
2014
2015
2016
2017
Thereafter
Total
(In thousands)
$
$
83,515
83,931
78,211
64,128
54,536
107,567
471,888
These amounts do not include contractual commitments under our long-term transportation agreements with HEP. HEP is a
consolidated VIE; all transactions with HEP are eliminated in these consolidated financial statements.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
NOTE 21: Segment Information
Our operations are organized into two reportable segments, Refining and HEP. Our operations that are not included in the Refining
and HEP segments are included in Corporate and Other. Intersegment transactions are eliminated in our consolidated financial
statements and are included in Consolidations and Eliminations.
The Refining segment represents the operations of the El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries and NK
Asphalt (aggregated as a reportable segment). Refining activities involve the purchase and refining of crude oil and wholesale and
branded marketing of refined products, such as gasoline, diesel fuel and jet fuel. These petroleum products are primarily marketed
in the Mid-Continent, Southwest and Rocky Mountain regions of the United States. Additionally, the Refining segment includes
specialty lubricant products produced at our Tulsa Refineries that are marketed throughout North America and are distributed in
Central and South America. NK Asphalt operates various asphalt terminals in Arizona and New Mexico.
The HEP segment includes all of the operations of HEP, a consolidated VIE, which owns and operates logistics assets consisting
of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities in the Mid-Continent, Southwest
and Rocky Mountain regions of the United States. The HEP segment also includes a 75% interest in UNEV (a consolidated
subsidiary of HEP) and a 25% interest in the SLC Pipeline. Revenues from the HEP segment are earned through transactions with
unaffiliated parties for pipeline transportation, rental and terminalling operations as well as revenues relating to pipeline
transportation services provided for our refining operations. Our revaluation of HEP’s assets and liabilities at March 1, 2008 (date
of reconsolidation) resulted in basis adjustments to our consolidated HEP balances. Therefore, our reported amounts for the HEP
segment may not agree to amounts reported in HEP’s periodic public filings.
The accounting policies for our segments are the same as those described in the summary of significant accounting policies (see
Note 1).
Year Ended December 31, 2012
Sales and other revenues
Depreciation and amortization
Income (loss) from operations
Capital expenditures
Total assets
Year Ended December 31, 2011
Sales and other revenues
Depreciation and amortization
Income (loss) from operations
Capital expenditures
Total assets
Year Ended December 31, 2010
Sales and other revenues
Depreciation and amortization
Income (loss) from operations
Capital expenditures
Refining (1)
HEP (2)
Corporate
and Other
Consolidations
and Eliminations
Consolidated
Total
$
$
$
$
$
$
$
$
$
$
$
$
$
$
20,042,955
181,247
2,879,383
278,705
6,702,872
$ 288,501
57,789
$
$ 133,723
$
44,929
$1,426,800
15,392,430
122,437
1,739,068
148,699
6,576,966
$ 212,995
$
33,288
$ 110,102
$ 216,215
$1,418,660
8,287,000
84,587
242,466
102,034
$ 182,093
28,949
$
$
92,287
$ 109,510
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(In thousands)
1,048
$
$
4,660
(126,840) $
$
11,629
$
2,531,967
(241,780) $
(828) $
(2,120) $
— $
(332,642) $
20,090,724
242,868
2,884,146
335,263
10,328,997
$
1,098
$
4,810
(117,677) $
$
9,327
$
1,997,600
(166,995) $
(828) $
$
55
— $
(416,983) $
15,439,528
159,707
1,731,548
374,241
9,576,243
$
412
$
4,675
(69,555) $
$
1,688
(146,576) $
(682) $
(2,200) $
— $
8,322,929
117,529
262,998
213,232
(1) The Refining segment reflects the operations of the El Dorado and Cheyenne Refineries beginning July 1, 2011 (date of Holly-Frontier
merger).
(2) HEP acquired our 75% interest in UNEV in July 2012. As a result, we have recast our HEP segment information to include the UNEV
Pipeline operations as a consolidated subsidiary of HEP for all periods presented. The UNEV Pipeline was previously presented under
Corporate and Other.
HEP segment revenues from external customers were $47.6 million, $46.4 million and $36.0 million for the years ended
December 31, 2012, 2011 and 2010, respectively.
92
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
NOTE 22: Supplemental Guarantor/Non-Guarantor Financial Information
Our obligations under the HollyFrontier Senior Notes have been jointly and severally guaranteed by the substantial majority of
our existing and future restricted subsidiaries (“Guarantor Restricted Subsidiaries”). These guarantees are full and unconditional.
HEP, in which we have a 44% ownership interest at December 31, 2012, and its subsidiaries (collectively, “Non-Guarantor Non-
Restricted Subsidiaries”), and certain of our other subsidiaries (“Non-Guarantor Restricted Subsidiaries”) have not guaranteed
these obligations.
The following condensed consolidating financial information is provided for HollyFrontier Corporation (the “Parent”), the
Guarantor Restricted Subsidiaries, the Non-Guarantor Restricted Subsidiaries and the Non-Guarantor Non-Restricted Subsidiaries.
The information has been presented as if the Parent accounted for its ownership in the Guarantor Restricted Subsidiaries, and the
Guarantor Restricted Subsidiaries accounted for the ownership of the Non-Guarantor Restricted Subsidiaries and Non-Guarantor
Non-Restricted Subsidiaries, using the equity method of accounting. The Guarantor Restricted Subsidiaries and the Non-Guarantor
Restricted Subsidiaries are collectively the “Restricted Subsidiaries.”
HEP acquired our 75% interest in UNEV in July 2012. As a result, we have recast our HEP segment information to include the
UNEV Pipeline operations as a consolidated subsidiary of HEP for all periods presented. The UNEV Pipeline was previously
presented as a Non-Guarantor Restricted Subsidiary.
Condensed Consolidating Balance Sheet
December 31, 2012
Parent
Guarantor
Restricted
Subsidiaries
Non-
Guarantor
Restricted
Subsidiaries
HollyFrontier
Corp. Before
Consolidation
of HEP
Non-Guarantor
Non-Restricted
Subsidiaries
(HEP Segment)
Eliminations
Eliminations
Consolidated
(In thousands)
$
$
1,748,808
630,579
4,788
$
3,652
7
627,262
$
2
—
—
ASSETS
Current assets:
Cash and cash equivalents
Marketable securities
Accounts receivable, net
Intercompany accounts receivable
(payable)
Inventories
Income taxes receivable
Prepayments and other
Total current assets
Properties, plants and equip, net
Marketable securities (long-term)
Investment in subsidiaries
Intangibles and other assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
Income taxes payable
Accrued liabilities
Deferred income tax liabilities
Total current liabilities
Long-term debt
Liability to HEP
Deferred income tax liabilities
Other long-term liabilities
Investment in HEP
Equity – HollyFrontier
Equity – noncontrolling interest
Total liabilities and equity
(546,655)
—
74,957
21,867
1,934,344
24,209
5,116
5,251,396
11,825
7,226,890
1,941
—
71,226
145,225
218,392
460,254
—
530,544
48,757
—
5,968,943
—
7,226,890
$
$
$
285,291
1,318,373
—
34,667
2,269,252
2,444,398
—
74,120
2,284,329
7,072,099
1,336,097
—
105,298
—
1,441,395
36,311
257,777
—
85,220
—
5,251,396
—
7,072,099
$
$
$
$
$
$
— $
—
—
—
261,364
—
—
—
261,366
—
—
—
25,000
286,366
—
—
—
—
—
—
(5,325,516)
(25,000)
$ (5,350,516) $
— $
—
581
(9)
572
—
— $
—
—
—
—
(25,000)
—
—
—
—
(5,325,516)
—
$ (5,350,516) $
1,175
—
210,499
74,120
—
286,366
93
1,752,462
630,586
632,050
—
1,318,373
74,957
56,534
4,464,962
2,468,607
5,116
—
2,296,154
9,234,839
1,338,038
—
177,105
145,216
1,660,359
471,565
257,777
531,719
133,977
210,499
5,968,943
—
9,234,839
$
$
$
$
5,237
—
38,097
—
1,259
—
2,360
46,953
1,014,556
—
—
365,291
1,426,800
12,030
—
23,705
—
35,735
864,673
—
—
28,683
—
382,207
115,502
1,426,800
$
$
$
$
— $
—
(35,917)
1,757,699
630,586
634,230
—
—
—
—
(5,733)
(41,650)
(288,463)
—
—
(2,529)
1,319,632
74,957
53,161
4,470,265
3,194,700
5,116
—
2,658,916
(332,642) $ 10,328,997
(35,917) $
1,314,151
—
—
(5,733)
195,077
—
145,216
(41,650)
1,654,444
—
1,336,238
(257,777)
—
4,951
536,670
(3,673)
158,987
(210,499)
—
(298,196)
6,052,954
589,704
474,202
(332,642) $ 10,328,997
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Balance Sheet
December 31, 2011 (1)
Parent
Guarantor
Restricted
Subsidiaries
Non-
Guarantor
Restricted
Subsidiaries
HollyFrontier
Corp. Before
Consolidation
of HEP
Non-Guarantor
Non-Restricted
Subsidiaries
(HEP Segment)
Eliminations
Eliminations
Consolidated
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents
Marketable securities
Accounts receivable, net
Intercompany accounts receivable
(payable)
Inventories
Income taxes receivable
Prepayments and other
Total current assets
Properties, plants and equip, net
Marketable securities (long-term)
Investment in subsidiaries
Intangibles and other assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
Income taxes payable
Accrued liabilities
Deferred income tax liabilities
Total current liabilities
Long-term debt
Liability to HEP
Deferred income tax liabilities
Other long-term liabilities
Equity – HollyFrontier
Equity – noncontrolling interest
Total liabilities and equity
$
$
1,575,891
210,886
8,317
(3,358) $
753
698,911
$
2
—
—
(629,712)
—
87,277
19,379
1,272,038
26,702
50,067
5,280,403
19,329
6,648,539
23,497
40,366
53,390
175,683
292,936
651,261
—
457,914
116,443
5,129,985
—
6,648,539
$
$
$
331,431
1,113,136
—
202,428
2,343,301
2,322,645
—
331,413
2,242,197
7,239,556
1,494,790
—
103,981
—
1,598,771
37,620
269,870
—
52,892
5,280,403
—
7,239,556
$
$
$
$
$
$
298,281
—
—
4
298,287
—
—
35,511
—
333,798
359
—
1,170
—
1,529
—
—
856
—
331,413
—
333,798
— $
—
—
—
—
—
—
—
—
—
(5,611,816)
—
$ (5,611,816) $
$
— $
—
—
—
—
—
—
—
—
(5,611,816)
—
$ (5,611,816) $
1,572,535
211,639
707,228
—
1,113,136
87,277
221,811
3,913,626
2,349,347
50,067
35,511
2,261,526
8,610,077
1,518,646
40,366
158,541
175,683
1,893,236
688,881
269,870
458,770
169,335
5,129,985
—
8,610,077
$
$
$
$
6,369
—
37,290
—
1,483
—
2,246
47,388
1,006,379
—
—
364,893
1,418,660
21,709
—
16,006
—
37,715
598,761
—
—
4,000
679,182
99,002
1,418,660
$
$
$
$
— $
—
(35,661)
1,578,904
211,639
708,857
—
—
—
(4,607)
(40,268)
(302,821)
—
(35,511)
(73,894)
(452,494) $
(35,661) $
—
(4,607)
—
(40,268)
(72,900)
(269,870)
4,951
(2,138)
(605,157)
532,888
(452,494) $
—
1,114,619
87,277
219,450
3,920,746
3,052,905
50,067
—
2,552,525
9,576,243
1,504,694
40,366
169,940
175,683
1,890,683
1,214,742
—
463,721
171,197
5,204,010
631,890
9,576,243
(1) Certain amounts have been revised to conform to our current year presentation in the Parent, Guarantor Restricted Subsidiary, Non-Guarantor
Restricted Subsidiary and Elimination columns.
94
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Statement of Income and Comprehensive Income
Year Ended December 31, 2012
Parent
Guarantor
Restricted
Subsidiaries
Non-
Guarantor
Restricted
Subsidiaries
HollyFrontier
Corp. Before
Consolidation
of HEP
Non-Guarantor
Non-Restricted
Subsidiaries
(HEP Segment)
Eliminations
Eliminations
Consolidated
Sales and other revenues
Operating costs and expenses:
Cost of products sold
Operating expenses
General and administrative
Depreciation and amortization
Total operating costs and
expenses
Income (loss) from operations
Other income (expense):
Earnings of equity method
investments
Interest income (expense)
Gain on sale of marketable
securities
Income before income taxes
Income tax provision
Net income
Less net income attributable to
noncontrolling interest
Net income attributable to
HollyFrontier stockholders
Comprehensive income
attributable to HollyFrontier
stockholders
$
494
$ 20,043,335
$
174
$
(In thousands)
— $
20,044,003
$
288,501
$
(241,780) $ 20,090,724
—
—
118,860
4,172
16,078,948
906,098
1,519
181,735
123,032
17,168,300
(122,538)
2,875,035
2,921,077
(41,564)
—
2,879,513
2,756,975
1,027,591
1,729,384
49,347
(3,631)
326
46,042
2,921,077
—
2,921,077
—
—
$
1,729,384
$
2,921,077
$
1,835,488
$
2,727,854
$
$
—
—
128
—
128
46
—
—
—
—
—
—
49,066
(2,970,865)
—
—
(2,970,865)
(2,970,865)
—
(2,970,865)
676
—
49,742
49,788
—
49,788
—
16,078,948
906,098
120,507
185,907
17,291,460
2,752,543
48,625
(44,519)
326
4,432
2,756,975
1,027,591
1,729,384
—
—
49,788
$ (2,970,865) $
1,729,384
49,788
$ (2,970,865) $
1,642,265
$
$
—
89,395
7,594
57,789
154,778
133,723
3,364
(57,219)
—
(53,855)
79,868
371
79,497
32,861
46,636
47,457
(238,305)
(527)
—
(828)
15,840,643
994,966
128,101
242,868
(239,660)
17,206,578
(2,120)
2,884,146
(49,066)
2,338
—
(46,728)
(48,848)
—
(48,848)
2,923
(99,400)
326
(96,151)
2,787,995
1,027,962
1,760,033
—
32,861
(48,848) $
1,727,172
(48,848) $
1,640,874
$
$
Condensed Consolidating Statement of Income and Comprehensive Income
Year Ended December 31, 2011
Parent
Guarantor
Restricted
Subsidiaries
Non-
Guarantor
Restricted
Subsidiaries
HollyFrontier
Corp. Before
Consolidation
of HEP
Non-Guarantor
Non-Restricted
Subsidiaries
(HEP Segment)
Eliminations
Eliminations
Consolidated
Sales and other revenues
Operating costs and expenses:
Cost of products sold
Operating expenses
General and administrative
Depreciation and amortization
Total operating costs and
expenses
Income (loss) from operations
Other income (expense):
Earnings of equity method
investments
Interest income (expense)
Merger transaction costs
Income before income taxes
Income tax provision
Net income
Less net income attributable to
noncontrolling interest
Net income attributable to
HollyFrontier stockholders
Comprehensive income
attributable to HollyFrontier
stockholders
$
1,008
$ 15,392,446
$
74
$
(In thousands)
— $
15,393,528
$
212,995
$
(166,995) $ 15,439,528
—
—
111,093
4,165
12,844,333
687,381
2,445
123,082
115,258
13,657,241
(114,250)
1,735,205
1,771,022
(38,619)
(15,114)
1,717,289
1,603,039
581,757
1,021,282
38,546
(2,729)
—
35,817
1,771,022
—
1,771,022
—
—
$
1,021,282
$
1,771,022
$
1,018,650
$
1,876,788
$
$
—
(362)
—
—
(362)
436
38,308
54
—
38,362
38,798
—
38,798
—
—
—
—
—
—
—
(1,809,820)
—
—
(1,809,820)
(1,809,820)
—
(1,809,820)
12,844,333
687,019
113,538
127,247
13,772,137
1,621,391
38,056
(41,294)
(15,114)
(18,352)
1,603,039
581,757
1,021,282
—
—
38,798
$ (1,809,820) $
1,021,282
38,798
$ (1,809,820) $
1,124,416
$
$
—
63,029
6,576
33,288
102,893
110,102
2,552
(38,209)
—
(35,657)
74,445
234
74,211
36,307
37,904
38,651
(164,255)
(1,967)
—
(828)
12,680,078
748,081
120,114
159,707
(167,050)
13,707,980
55
1,731,548
(38,308)
2,464
—
(35,844)
(35,789)
—
(35,789)
2,300
(77,039)
(15,114)
(89,853)
1,641,695
581,991
1,059,704
—
36,307
(35,789) $
1,023,397
(35,789) $
1,127,278
$
$
95
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Statement of Income and Comprehensive Income
Year Ended December 31, 2010
Parent
Guarantor
Restricted
Subsidiaries
Non-
Guarantor
Restricted
Subsidiaries
HollyFrontier
Corp. Before
Consolidation
of HEP
Non-Guarantor
Non-Restricted
Subsidiaries
(HEP Segment)
Eliminations
Eliminations
Consolidated
Sales and other revenues
Operating costs and expenses:
Cost of products sold
Operating expenses
General and administrative
Depreciation and amortization
Total operating costs and expenses
Income (loss) from operations
Other income (expense):
Earnings of equity method
investments
Interest income (expense)
Income before income taxes
Income tax provision
Net income
Less net income attributable to
noncontrolling interest
Net income attributable to
HollyFrontier stockholders
Comprehensive income
attributable to HollyFrontier
stockholders
$
412
$
8,287,000
$
— $
(In thousands)
— $
8,287,412
$
182,093
$
(146,576) $
8,322,929
—
2,411
62,130
3,745
68,286
(67,874)
265,367
(33,838)
231,529
163,655
59,016
104,639
7,510,357
449,349
990
85,517
8,046,213
240,787
30,036
(5,456)
24,580
265,367
—
265,367
—
—
$
$
104,639
103,279
$
$
265,367
265,443
$
$
—
2
—
—
2
(2)
29,998
40
30,038
30,036
—
30,036
—
30,036
30,036
—
—
—
—
—
—
(295,403)
—
(295,403)
(295,403)
—
(295,403)
7,510,357
451,762
63,120
89,262
8,114,501
172,911
29,998
(39,254)
(9,256)
163,655
59,016
104,639
—
—
(295,403) $
104,639
(295,403) $
103,355
$
$
$
$
—
53,138
7,719
28,949
89,806
92,287
2,393
(36,240)
(33,847)
58,440
296
58,144
29,087
29,057
29,795
(143,208)
(486)
—
(682)
7,367,149
504,414
70,839
117,529
(144,376)
8,059,931
(2,200)
262,998
(29,998)
2,466
(27,532)
(29,732)
—
(29,732)
2,393
(73,028)
(70,635)
192,363
59,312
133,051
—
29,087
(29,732) $
103,964
(29,732) $
103,418
$
$
96
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2012
Parent
Guarantor
Restricted
Subsidiaries
Non-
Guarantor
Restricted
Subsidiaries
HollyFrontier
Corp. Before
Consolidation
of HEP
Non-Guarantor
Non-Restricted
Subsidiaries
(HEP Segment)
Eliminations
Consolidated
Cash flows from operating activities
$
1,596,358
$
(33,004) $
1,286
$
(In thousands)
1,564,640
$
162,036
$
(63,989) $
1,662,687
Cash flows from investing activities
Additions to properties, plants and equip
Additions to properties, plants and equip – HEP
Investment in Sabine Biofuels
Purchases of marketable securities
Sales and maturities of marketable securities
Cash flows from financing activities
Net borrowings under credit agreement – HEP
Repayment of promissory notes
Net proceeds from issuance of senior notes -
HEP
Principal tender on senior notes
Principal tender on senior notes - HEP
Purchase of treasury stock
Structured stock repurchase agreement
Contribution from joint venture partner
Contribution from general partner
Distribution from HEP upon UNEV transfer
Dividends
Distributions to noncontrolling interest
Excess tax benefit from equity-based
compensation
Purchase of units for incentive grants - HEP
Deferred financing costs
Other
Cash and cash equivalents
Increase (decrease) for the period
Beginning of period
End of period
(7,965)
—
—
(671,552)
296,780
(382,737)
—
—
—
(205,000)
—
(209,600)
8,620
—
—
—
(658,085)
—
23,361
—
—
—
(1,040,704)
(282,369)
—
(2,000)
—
931
(283,438)
—
72,900
—
—
—
—
—
—
(9,000)
260,922
—
—
—
—
(67)
(1,303)
323,452
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1,286)
—
—
—
—
—
—
—
(1,286)
(290,334)
—
(2,000)
(671,552)
297,711
(666,175)
—
72,900
—
(205,000)
—
(209,600)
8,620
—
(10,286)
260,922
(658,085)
—
23,361
—
(67)
(1,303)
(718,538)
—
(44,929)
—
—
—
(44,929)
221,000
(72,900)
294,750
—
(185,000)
—
—
6,000
10,286
(260,922)
—
(122,777)
—
(5,240)
(3,238)
(198)
(118,239)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
63,989
—
—
—
—
63,989
(290,334)
(44,929)
(2,000)
(671,552)
297,711
(711,104)
221,000
—
294,750
(205,000)
(185,000)
(209,600)
8,620
6,000
—
—
(658,085)
(58,788)
23,361
(5,240)
(3,305)
(1,501)
(772,788)
172,917
1,575,891
1,748,808
$
$
7,010
(3,358)
3,652
$
—
2
2
$
179,927
1,572,535
1,752,462
$
(1,132)
6,369
5,237
$
—
—
— $
178,795
1,578,904
1,757,699
97
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2011
Parent
Guarantor
Restricted
Subsidiaries
Non-
Guarantor
Restricted
Subsidiaries
HollyFrontier
Corp. Before
Consolidation
of HEP
Non-Guarantor
Non-Restricted
Subsidiaries
(HEP Segment)
(In thousands)
Eliminations
Consolidated
Cash flows from operating activities
$
1,933,208
$
(669,379) $
5,887
$
1,269,716
$
108,948
$
(40,273) $
1,338,391
Cash flows from investing activities:
Additions to properties, plants and equip
Additions to properties, plants and equip – HEP
Increase in cash due to merger with Frontier
Investment in Sabine Biofuels
Purchases of marketable securities
Sales and maturities of marketable securities
Cash flows from financing activities:
Net borrowings under credit agreement – HEP
Repayments of promissory notes
Proceeds from issuance of common units – HEP
Purchase of treasury stock
Principal tender on senior notes – HFC
Contribution to HEP
Contribution from UNEV joint venture partner
Dividends
Distributions to noncontrolling interest
Excess tax benefit from equity-based
compensation
Purchase of units for restricted grants - HEP
Deferred financing costs
Other
Cash and cash equivalents
Increase (decrease) for the period:
Beginning of period
End of period
(7,585)
—
182
(9,125)
(561,899)
301,020
(277,407)
—
—
—
(42,795)
(8,203)
—
—
(252,133)
—
1,804
—
(8,665)
—
(309,992)
(150,441)
—
872,557
—
—
—
722,116
—
77,100
—
—
—
(123,000)
—
—
—
—
—
—
(1,160)
(47,060)
—
—
—
—
—
—
—
—
—
—
—
—
(5,887)
—
—
—
—
—
—
—
(5,887)
(158,026)
—
872,739
(9,125)
(561,899)
301,020
444,709
—
77,100
—
(42,795)
(8,203)
(128,887)
—
(252,133)
—
1,804
—
(8,665)
(1,160)
(362,939)
—
(216,215)
—
—
—
—
(216,215)
41,000
(77,100)
75,815
—
—
128,887
33,500
—
(91,506)
—
(1,641)
(3,150)
(221)
105,584
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
40,632
—
—
—
(359)
40,273
(158,026)
(216,215)
872,739
(9,125)
(561,899)
301,020
228,494
41,000
—
75,815
(42,795)
(8,203)
—
33,500
(252,133)
(50,874)
1,804
(1,641)
(11,815)
(1,740)
(217,082)
1,345,809
230,082
1,575,891
$
$
5,677
(9,035)
(3,358) $
—
2
2
$
1,351,486
221,049
1,572,535
$
(1,683)
8,052
6,369
$
—
—
— $
1,349,803
229,101
1,578,904
98
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2010
Parent
Guarantor
Restricted
Subsidiaries
Non-
Guarantor
Restricted
Subsidiaries
HollyFrontier
Corp. Before
Consolidation
of HEP
Non-Guarantor
Non-Restricted
Subsidiaries
(HEP Segment)
(In thousands)
Eliminations
Consolidated
Cash flows from operating activities
$
140,934
$
70,949
$
— $
211,883
$
107,721
$
(36,349) $
283,255
Cash flows from investing activities:
Additions to properties, plants and equip
Additions to properties, plants and equip – HEP
Proceeds from sale of assets
Cash flows from financing activities:
Net repayments under credit agreement – HEP
Proceeds from issuance of senior notes – HEP
Purchase of treasury stock
Contribution to HEP
Contribution from UNEV joint venture partner
Dividends
Purchase price in excess of transferred basis in
assets
Distributions to noncontrolling interest
Excess tax benefit from equity-based
compensation
Purchase of units for restricted grants - HEP
Deferred financing costs
Other
(1,573)
—
—
(1,573)
—
—
(1,368)
—
—
(31,868)
—
—
(1,094)
—
(2,627)
118
(36,839)
(102,149)
—
39,040
(63,109)
—
—
—
(57,000)
—
—
54,046
—
—
—
—
(1,444)
(4,398)
Cash and cash equivalents
Increase (decrease) for the period:
Beginning of period
End of period
102,522
127,560
230,082
$
3,442
(12,477)
(9,035) $
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
2
(103,722)
—
39,040
(64,682)
—
—
(1,368)
(57,000)
—
(31,868)
54,046
—
(1,094)
—
(2,627)
(1,326)
(41,237)
—
(109,510)
(39,040)
(148,550)
(47,000)
147,540
—
57,000
23,500
—
(54,046)
(84,426)
—
(2,704)
(494)
—
39,370
—
—
—
—
—
—
—
—
—
—
—
35,933
—
—
—
416
36,349
105,964
115,085
221,049
$
$
(1,459)
9,511
8,052
$
—
—
— $
(103,722)
(109,510)
—
(213,232)
(47,000)
147,540
(1,368)
—
23,500
(31,868)
—
(48,493)
(1,094)
(2,704)
(3,121)
(910)
34,482
104,505
124,596
229,101
99
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
NOTE 23: Significant Customers
All revenues are domestic revenues, except for refining segment sales of gasoline and diesel fuel for export into Mexico. We have
two significant customers (Sinclair and Shell Oil), each accounting for 10% or more of our annual revenues. Sinclair accounted
for $2,106.6 million (10%), $2,035.1 million (13%) and $1,616.0 million (19%) of our revenues for the years ended December 31,
2012, 2011 and 2010, respectively, and Shell Oil accounted for $2,323.6 million (12%) and $1,540.6 million (10%) for the years
ended December 31, 2012 and 2011, respectively. Our export sales were to an affiliate of PEMEX and accounted for $429.4 million
(2%), $370.0 million (2%) and $323.2 million (4%) of our revenues for the years ended December 31, 2012, 2011 and 2010,
respectively.
NOTE 24: Quarterly Information (Unaudited)
$
$
$
$
$
$
$
$
$
$
$
$
Year Ended December 31, 2012
Sales and other revenues
Operating costs and expenses
Income from operations
Income before income taxes
Net income attributable to
HollyFrontier stockholders
Net income per share attributable to
HollyFrontier stockholders - basic
Net income per share attributable to
HollyFrontier stockholders - diluted $
$
Dividends per common share
Average number of shares of common
stock outstanding:
Basic
Diluted
Year Ended December 31, 2011
Sales and other revenues
Operating costs and expenses
Income from operations
Income before income taxes
Net income attributable to
HollyFrontier stockholders
Net income per share attributable to
HollyFrontier stockholders - basic
Net income per share attributable to
HollyFrontier stockholders - diluted $
$
Dividends per common share
Average number of shares of common
stock outstanding:
Basic
Diluted
First
Quarter
4,931,738
4,512,174
419,564
387,426
241,696
1.16
1.16
0.600
208,531
209,138
2,326,585
2,167,486
159,099
140,022
84,694
0.80
0.79
0.075
Second
Quarter
Third
Quarter
(In thousands, except per share data)
Fourth
Quarter
Year
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
4,806,681
3,993,544
813,137
788,088
493,499
2.40
2.39
0.650
205,727
206,481
2,967,133
2,636,954
330,179
313,794
192,235
1.80
1.79
0.075
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
5,204,798
4,226,494
978,304
960,272
600,373
2.95
2.94
1.150
203,557
204,434
5,173,398
4,304,191
869,207
835,769
523,088
2.50
2.48
0.588
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
5,147,507
4,474,366
673,141
652,209
$ 20,090,724
$ 17,206,578
2,884,146
$
2,787,995
$
391,604
1.92
1.92
0.700
$
$
$
$
1,727,172
8.41
8.38
3.100
203,458
204,453
205,289
206,184
4,972,412
4,599,349
373,063
352,110
$ 15,439,528
$ 13,707,980
1,731,548
$
1,641,695
$
223,380
1.07
1.06
0.600
$
$
$
$
1,023,397
6.46
6.42
1.338
106,614
107,266
106,730
107,340
209,583
210,579
209,319
210,159
158,486
159,294
100
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 accountants on matters involving accounting
and financial disclosure.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures. Our principal executive officer and principal financial officer have evaluated,
as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Exchange Act as of the end of the period covered by this
annual report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the
information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and
communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to
allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods
specified in the Securities and Exchange Commission's rules and forms. Based upon the evaluation, our principal executive officer
and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance
level as of December 31, 2012.
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 “Management's Report on its Assessment of the Company's Internal Control Over Financial Reporting” and “Report
of the Independent Registered Public Accounting Firm.”
Item 9B. Other Information
There have been no events that occurred in the fourth quarter of 2012 that would need to be reported on Form 8-K that have not
previously been reported.
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information required by Items 401, 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K in response to this item will
be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2013 and is incorporated
herein by reference.
Item 11. Executive Compensation
The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K in response to this item will be set forth in our
definitive proxy statement for the annual meeting of stockholders to be held on May 15, 2013 and is incorporated herein by
reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The equity compensation plan information required by Item 201(d) and the information required by Item 403 of Regulation S-K
in response to this item will be set forth in our definitive proxy statement for the annual meeting of stockholders to be held on
May 15, 2013 and is incorporated herein by reference.
101
Table of Content
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by Items 404 and 407(a) of Regulation S-K in response to this item will be set forth in our definitive
proxy statement for the annual meeting of stockholders to be held on May 15, 2013 and is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
The information required by Item 9(e) of Schedule 14A in response to this item will be set forth in our definitive proxy statement
for the annual meeting of stockholders to be held on May 15, 2013 and is incorporated herein by reference.
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)
Documents filed as part of this report
(1)
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2012 and 2011
Consolidated Statements of Income for the years ended
December 31, 2012, 2011 and 2010
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2012, 2011 and 2010
Consolidated Statements of Cash Flows for the years ended
December 31, 2012, 2011 and 2010
Consolidated Statements of Equity for the years ended
December 31, 2012, 2011 and 2010
Notes to Consolidated Financial Statements
(2)
Index to Consolidated Financial Statement Schedules
Page in
Form 10-K
57
58
59
60
61
62
63
All schedules are omitted since the required information is not present or is not present in amounts sufficient to require
submission of the schedule, or because the information required is included in the consolidated financial statements or
notes thereto.
(3)
Exhibits
The Exhibit Index on pages 105 to 113 of this Annual Report on Form 10-K lists the exhibits that are filed or furnished,
as applicable, as part of this Annual Report on Form 10-K.
102
Table of Content
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Date: February 27, 2013
HOLLYFRONTIER CORPORATION
(Registrant)
/s/ Michael C. Jennings
Michael C. Jennings
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and as of the date indicated.
Signature
Capacity
Date
/s/ Michael C. Jennings
Chief Executive Officer and
February 27, 2013
Michael C. Jennings
President
/s/ Douglas S. Aron
Douglas S. Aron
/s/ J.W. Gann, Jr.
J.W. Gann, Jr.
Executive Vice President and
February 27, 2013
Chief Financial Officer
(Principal Financial Officer)
Vice President, Controller and
February 27, 2013
Chief Accounting Officer
(Principal Accounting Officer)
/s/ Denise C. McWatters
Senior Vice President, General
February 27, 2013
Denise C. McWatters
Counsel and Secretary
/s/ Douglas Y. Bech
Douglas Y. Bech
/s/ Buford P. Berry
Buford P. Berry
/s/ Leldon Echols
Leldon Echols
/s/ R. Kevin Hardage
R. Kevin Hardage
Director
Director
Director
Director
February 27, 2013
February 27, 2013
February 27, 2013
February 27, 2013
/s/ Robert J. Kostelnik
Director
February 27, 2013
Robert J. Kostelnik
/s/ James H. Lee
James H. Lee
Director
February 27, 2013
/s/ Robert G. McKenzie
Director
February 27, 2013
Robert G. McKenzie
103
Table of Content
Signature
Capacity
Date
/s/ Franklin Myers
Franklin Myers
/s/ Michael E. Rose
Michael E. Rose
Director
Director
February 27, 2013
February 27, 2013
/s/ Tommy A. Valenta
Director
February 27, 2013
Tommy A. Valenta
104
Table of Content
Exhibit
Number
Description
HOLLYFRONTIER CORPORATION
INDEX TO EXHIBITS
Exhibits are numbered to correspond to the exhibit table
in Item 601 of Regulation S-K
2.1
2.2
2.3
2.4
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
Asset Sale and Purchase Agreement, dated October 19, 2009, between Holly Refining & Marketing-Tulsa LLC, HEP
Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1 of Registrant's Current
Report on Form 8-K filed October 21, 2009, File No. 1-03876).
Amendment No. 1 to Asset Sale and Purchase Agreement, dated December 1, 2009, between Holly Refining &
Marketing-Tulsa LLC, HEP Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 2.1
of Registrant's Current Report on Form 8-K filed December 7, 2009, File No. 1-03876).
Asset Sale and Purchase Agreement, dated April 15, 2009, between Holly Refining & Marketing-Midcon, L.L.C. and
Sunoco, Inc. (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed April 16, 2009,
File No. 1-03876).
Agreement and Plan of Merger among Holly Corporation, North Acquisition, Inc. and Frontier Oil Corporation, dated
February 21, 2011 (incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed February
22, 2011, File No. 1-03876).
Amended and Restated Certificate of Incorporation of HollyFrontier Corporation (incorporated by reference to Exhibit
3.1 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).
Amended and Restated Bylaws of HollyFrontier Corporation (incorporated by reference to Exhibit 3.1 of Registrant's
Current Report on Form 8-K filed November 21, 2011, File No. 1-03876).
Indenture, dated February 28, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors
and U.S. Bank National Association, providing for the issuance of 6.25% Senior Notes due 2015 (incorporated by
reference to Exhibit 4.1 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed March 4, 2005, File No.
1-32225).
First Supplemental Indenture, dated March 10, 2005, among HEP Fin-Tex/Trust-River, L.P., Holly Energy Partners,
L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference
to Exhibit 4.5 of Holly Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarterly period ended March
31, 2005, File No. 1-32225).
Second Supplemental Indenture, dated April 27, 2005, among Holly Energy Partners, L.P., Holly Energy Finance Corp.,
the Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 of Holly Energy Partners,
L.P.'s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005, File No. 1-32225).
Third Supplemental Indenture, dated June 11, 2009, among Lovington-Artesia, L.L.C., Holly Energy Partners, L.P.,
Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to
Exhibit 4.8 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876).
Fourth Supplemental Indenture, dated June 29, 2009, among HEP SLC, LLC, Holly Energy Partners, L.P., Holly Energy
Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 of
Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876).
Fifth Supplemental Indenture, dated July 13, 2009, among HEP Tulsa LLC, Holly Energy Partners, L.P., Holly Energy
Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10
of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-03876).
Sixth Supplemental Indenture, dated December 15, 2009, among Roadrunner Pipeline, L.L.C., Holly Energy Partners,
L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference
to Exhibit 4.11 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No.
1-03876).
Seventh Supplemental Indenture, dated April 14, 2010, among Holly Energy Storage- Tulsa LLC, Holly Energy
Storage-Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank
National Association (incorporated by reference to Exhibit 4.1 of Holly Energy Partners, L.P.'s Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2010, File No. 1-32225).
105
Table of Content
Exhibit
Number
Description
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
Eighth Supplemental Indenture, dated June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly
Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit
4.2 of Holly Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010, File
No. 1-32225).
Ninth Supplemental Indenture, dated December 29, 2011, among Cheyenne Logistics LLC, El Dorado Logistics LLC,
Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.12 of Holly Energy Partners, L.P.'s Annual Report on Form 10-K for its fiscal
year ended December 31, 2011, File No. 1-32225).
Tenth Supplemental Indenture, dated March 12, 2012, among Holly Energy Partners, L.P., Holly Energy Finance Corp.,
the Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of Holly Energy Partners,
L.P.'s Current Report on Form 8-K filed March 12, 2012, File No. 1-32225).
Form of 6.25% Senior Note Due 2015 (included as Exhibit A to the Indenture included as Exhibit 4.1 hereto)
(incorporated by reference to Exhibit 4.2 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed March 4,
2005, File No. 1-32225).
Form of Notation of Guarantee (included as Exhibit E to the Indenture included as Exhibit 4.1 hereto) (incorporated
by reference to Exhibit 4.3 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed March 4, 2005, File No.
1-32225).
Indenture, dated September 17, 2008, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil
Corporation), the Guarantors and Wells Fargo Bank, National Association, providing for the issuance of 8.5% Senior
Notes due 2016 (incorporated by reference to Exhibit 4.1 of Frontier Oil Corporation's Current Report on Form 8-K
filed September 17, 2008, File No. 1-07627).
First Supplemental Indenture, dated September 17, 2008, among HollyFrontier Corporation (as successor-in-interest
to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference
to Exhibit 4.2 of Frontier Oil Corporation's Current Report on Form 8-K filed September 17, 2008, File No. 1-07627).
Second Supplemental Indenture, dated May 26, 2011, among HollyFrontier Corporation (as successor-in-interest to
Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to
Exhibit 4.1 of Frontier Oil Corporation's Current Report on Form 8-K filed May 27, 2011, File Number 1-07627).
Third Supplemental Indenture, dated July 1, 2011, among HollyFrontier Corporation (as successor-in-interest to
Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to
Exhibit 4.2 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).
Form of 8.5% Senior Note Due 2016 (incorporated by reference to Exhibit 4.3 of Frontier Oil Corporation's Current
Report on Form 8-K filed September 17, 2008, File Number 1-07627).
Indenture, dated June 10, 2009, among Holly Corporation, the Guarantors and U.S. Bank Trust National Association,
providing for the issuance of 9.875% Senior Notes due 2017 (includes the form of certificate for the notes issued
thereunder) (incorporated by reference to Exhibit 4.1 of Registrant's Current Report on Form 8-K filed June 11, 2009,
File No. 1-03876).
First Supplemental Indenture, dated June 14, 2011, among Holly Corporation, the Guarantors and U.S. Bank Trust
National Association (incorporated by reference to Exhibit 4.1 of Registrant's Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 2011, File No. 1-03876).
Second Supplemental Indenture, dated July 18, 2011, among HollyFrontier Corporation, the Guarantors and U.S. Bank
Trust National Association (incorporated by reference to Exhibit 4.11 of Registrant's Quarterly Report on Form 10-Q
for the quarterly period ended September 30, 2011, File No. 1-03876).
Indenture, dated March 10, 2010, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors
and U.S. Bank National Association, providing for the issuance of 8.25% Senior Notes due 2018 (incorporated by
reference to Exhibit 4.1 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed March 11, 2010, File No.
1-32225).
106
Table of Content
Exhibit
Number
4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
4.33
10.1
10.2
10.3
Description
First Supplemental Indenture, dated April 14, 2010, among Holly Energy Storage-Tulsa LLC, Holly Energy Storage-
Lovington LLC, Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National
Association (incorporated by reference to Exhibit 4.3 of Holly Energy Partners, L.P.'s Quarterly Report on Form 10-
Q for the quarterly period ended June 30, 2010, File No. 1-32225).
Second Supplemental Indenture, dated June 4, 2010, among HEP Operations LLC, Holly Energy Partners, L.P., Holly
Energy Finance Corp., the other Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit
4.4 of Holly Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010, File
No. 1-32225).
Third Supplemental Indenture, dated December 29, 2011, among Cheyenne Logistics LLC, El Dorado Logistics LLC,
Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.16 of Holly Energy Partners, L.P.'s Annual Report on Form 10-K for its fiscal
year ended December 31, 2011, File No. 1-32225).
Fourth Supplemental Indenture, dated August 6, 2012, among HEP UNEV Holdings LLC, HEP UNEV Pipeline LLC,
Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.1 to Registrant's Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 2012, File No. 1-03876).
Indenture, dated November 22, 2010, among HollyFrontier Corporation (as successor-in-interest to Frontier Oil
Corporation), the Guarantors and Wells Fargo Bank, National Association, providing for the issuance of 6 7/8% Senior
Notes due 2018 (incorporated by reference to Exhibit 4.1 of Frontier Oil Corporation's Current Report on Form 8-K
filed November 22, 2010, File Number 1-07627).
First Supplemental Indenture, dated November 22, 2010, among HollyFrontier Corporation (as successor-in-interest
to Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference
to Exhibit 4.2 of Frontier Oil Corporation's Current Report on Form 8-K filed November 22, 2010, File Number
1-07627).
Second Supplement Indenture, dated May 26, 2011, among HollyFrontier Corporation (as successor-in-interest to
Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to
Exhibit 4.2 of Frontier Oil Corporation's Current Report on Form 8-K filed May 27, 2011, File No. 1-07627).
Third Supplemental Indenture, dated July 1, 2011, among HollyFrontier Corporation (as successor-in-interest to
Frontier Oil Corporation), the Guarantors and Wells Fargo Bank, National Association (incorporated by reference to
Exhibit 4.1 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).
Form of 6 7/8% Senior Note Due 2018 (incorporated by reference to Exhibit 4.3 of Frontier Oil Corporation's Current
Report on form 8-K filed November 22, 2010, file Number 1-07627).
Indenture, dated March 12, 2012, among Holly Energy Partners, L.P., Holly Energy Finance Corp., the Guarantors
and U.S. Bank National Association, providing for the issuance of 6.50% Senior Notes due 2020 (incorporated by
reference to Exhibit 4.1 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed March 12, 2012, File No.
1-32225).
First Supplemental Indenture, dated August 6, 2012, among HEP UNEV Holdings LLC, HEP UNEV Pipeline LLC,
Holly Energy Partners, L.P., Holly Energy Finance Corp., the other Guarantors and U.S. Bank National Association
(incorporated by reference to Exhibit 4.2 of the Registrant's Quarterly Report on Form 10-Q for the quarterly period
ended September 30, 2012, File No. 1-03876).
Option Agreement, dated January 31, 2008, among Holly Corporation, Holly UNEV Pipeline Company, Navajo
Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy Partners, L.P., HEP
Logistics GP, L.L.C. and Holly Energy Partners – Operating, L.P. (incorporated by reference to Exhibit 10.1 of
Registrant's Current Report on Form 8-K filed February 5, 2008, File No. 1-03876).
First Amendment to Option Agreement, dated February 11, 2010, among Holly Corporation, Holly UNEV Pipeline
Company, Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics Holdings, L.P., Holly Energy
Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners – Operating L.P. (incorporated by reference to
Exhibit 10.2 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).
Termination of Option Agreement, dated July 12, 2012, among HollyFrontier Corporation, HEP UNEV Pipeline LLC
(f/k/a Holly UNEV Pipeline Company), Navajo Pipeline Co., L.P., Holly Logistic Services, L.L.C., HEP Logistics
Holdings, L.P., Holly Energy Partners, L.P., HEP Logistics GP, L.L.C. and Holly Energy Partners – Operating, L.P.
(incorporated by reference to Exhibit 10.6 of Registrant's Quarterly Report on Form 10-Q for the quarterly period
ended June 30, 2012, File No. 1-03876).
107
Table of Content
Exhibit
Number
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
Description
Amended and Restated Intermediate Pipelines Agreement, dated June 1, 2009, among Holly Corporation, Navajo
Refining Company, L.L.C, Holly Energy Partners, L.P., Holly Energy Partners – Operating, L.P., HEP Pipeline, L.L.C.,
Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistics Services, L.L.C. and HEP Logistics GP,
L.L.C. (incorporated by reference to Exhibit 10.2 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed
June 5, 2009, File No. 1-32225).
Amendment to Amended and Restated Intermediate Pipelines Agreement, dated December 9, 2010, among Navajo
Refining Company, L.L.C, Holly Energy Partners, L.P., Holly Energy Partners – Operating, L.P., HEP Pipeline, L.L.C.,
Lovington-Artesia, L.L.C., HEP Logistics Holdings, L.P., Holly Logistics Services, L.L.C. and HEP Logistics GP,
L.L.C. (incorporated by reference to Exhibit 10.4 of Registrant's Annual Report on Form 10-K for its fiscal year ended
December 31, 2010, File No. 1-03876).
Assignment and Assumption Agreement (Amended and Restated Intermediate Pipelines Agreement), effective January
1, 2011, between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated
by reference to Exhibit 10.5 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010,
File No. 1-03876).
Tulsa Equipment and Throughput Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa
LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.3 of Holly Energy Partners L.P.'s Current Report
on Form 8-K filed August 6, 2009, File No. 1-32225).
Amendment to Tulsa Equipment and Throughput Agreement, dated December 9, 2010, among Holly Refining &
Marketing - Tulsa LLC and HEP Tulsa LLC (incorporated by reference to Exhibit 10.7 of Registrant's Annual Report
on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).
Assignment and Assumption Agreement (Tulsa Equipment and Throughput Agreement), effective January 1, 2011,
between Holly Refining & Marketing - Tulsa, LLC and Holly Refining & Marketing Company LLC (incorporated by
reference to Exhibit 10.8 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010,
File No. 1-03876).
Tulsa Purchase Option Agreement, dated August 1, 2009, between Holly Refining & Marketing - Tulsa LLC and HEP
Tulsa LLC (incorporated by reference to Exhibit 10.4 of Holly Energy Partners L.P.'s Current Report on Form 8-K
filed August 6, 2009, File No. 1-32225).
Amended and Restated Crude Pipelines and Tankage Agreement, dated December 1, 2009, among Navajo Refining
Company, L.L.C., Holly Refining & Marketing Company - Woods Cross, Holly Refining & Marketing Company,
Holly Energy Partners - Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference
to Exhibit 10.8 of Holly Energy Partners, L.P.'s Current Report on Form 8-K filed December 7, 2009, File No. 1-32225).
Letter Agreement, dated October 14, 2011, regarding the Amended and Restated Crude Pipelines and Tankage
Agreement, dated December 1, 2009 (incorporated by reference to Exhibit 10.14 of the Registrant's Quarterly Report
on Form 10-Q for the quarterly period ended September 30, 2011, File No. 1-03876).
Amended and Restated Refined Product Pipelines and Terminals Agreement, dated December 1, 2009, among Navajo
Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross, Holly Energy Partners - Operating,
L.P., HEP Pipeline Assets, Limited Partnership, HEP Pipeline, L.L.C., HEP Refining Assets, L.P., HEP Refining, L.L.C.,
HEP Mountain Home, L.L.C. and HEP Woods Cross, L.L.C. (incorporated by reference to Exhibit 10.9 of Holly Energy
Partners, L.P.'s Current Report on Form 8-K filed December 7, 2009, File No. 1-32225).
Assignment and Assumption Agreement (Amended and Restated Refined Product Pipelines and Terminals Agreement),
effective January 1, 2011, among Navajo Refining Company, L.L.C., Holly Refining & Marketing - Woods Cross and
Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.12 of Registrant's Annual Report
on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).
Pipeline Throughput Agreement (Roadrunner), dated December 1, 2009, between Navajo Refining Company, L.L.C.
and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.4 of Holly Energy Partners, L.P.'s
Current Report on Form 8-K filed December 7, 2009, File No. 1-32225).
Assignment and Assumption Agreement (Pipeline Throughput Agreement (Roadrunner)), effective January 1, 2011,
between Navajo Refining Company, L.L.C. and Holly Refining & Marketing Company LLC (incorporated by reference
to Exhibit 10.14 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2010, File No.
1-03876).
108
Table of Content
Exhibit
Number
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
Description
First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East), dated March
31, 2010, among Holly Refining & Marketing - Tulsa LLC, HEP Tulsa LLC and Holly Energy Storage - Tulsa LLC
(incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed April 6, 2010, File No.
1-03876).
Amendment to First Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement (Tulsa East),
dated June 11, 2010, between Holly Refining & Marketing - Tulsa LLC, HEP Tulsa LLC and Holly Energy Storage -
Tulsa LLC (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.'s Quarterly Report on Form 10-
Q for the quarterly period ended June 30, 2010, File No. 1-32225).
Assignment and Assumption Agreement (First Amended and Restated Pipelines, Tankage and Loading Rack
Throughput Agreement (Tulsa East)), effective January 1, 2011, between Holly Refining & Marketing - Tulsa LLC
and Holly Refining & Marketing Company LLC (incorporated by reference to Exhibit 10.17 of Registrant's Annual
Report on Form 10-K for its fiscal year ended December 31, 2010, File No. 1-03876).
Second Amended and Restated Pipelines, Tankage and Loading Rack Throughput Agreement, dated August 31, 2011,
between Holly Refining & Marketing - Tulsa LLC, HEP Tulsa LLC and Holly Energy Storage - Tulsa LLC (incorporated
by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed September 1, 2011, File No. 1-03876).
Indemnification Proceeds and Payments Allocation Agreement, dated December 1, 2009, between HEP Tulsa LLC
and Holly Refining & Marketing - Tulsa LLC (incorporated by reference to Exhibit 10.2 of Registrant's Current Report
on Form 8-K filed December 7, 2009, File No. 1-03876).
Pipeline Systems Operating Agreement, dated February 8, 2010, among Navajo Refining Company, L.L.C., Lea
Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing - Tulsa LLC and Holly
Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.1 of Holly Energy Partners, L.P.'s Current
Report on Form 8-K filed February 9, 2010, File No. 1-32225).
First Amendment to Pipeline Systems Operating Agreement, dated March 31, 2010, among Navajo Refining Company,
L.L.C., Lea Refining Company, Woods Cross Refining Company, L.L.C., Holly Refining & Marketing - Tulsa LLC
and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.5 of Registrant's Current Report
on Form 8-K filed April 6, 2010, File No. 1-03876).
Loading Rack Throughput Agreement (Lovington), dated March 31, 2010, between Navajo Refining Company, L.L.C.
and Holly Energy Storage-Lovington LLC (incorporated by reference to Exhibit 10.2 of Registrant's Current Report
on Form 8-K filed April 6, 2010, File No. 1-03876).
First Amended and Restated Lease and Access Agreement (East Tulsa), dated March 31, 2010, among Holly Refining
& Marketing-Tulsa, HEP Tulsa LLC and Holly Energy Storage-Tulsa LLC (incorporated by reference to Exhibit 10.4
of Registrant's Current Report on Form 8-K filed April 6, 2010, File No. 1-03876).
LLC Interest Purchase Agreement, dated November 9, 2011, among HollyFrontier Corporation, Frontier Refining
LLC, Frontier El Dorado Refining LLC, Holly Energy Partners-Operating, L.P. and Holly Energy Partners, L.P.
(incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed November 10, 2011, File
No. 1-03876).
First Amended and Restated Tankage, Loading Rack and Crude Oil Receiving Throughput Agreement (Cheyenne),
dated November 11, 2011, between Frontier Refining LLC and Cheyenne Logistics LLC (incorporated by reference
to Exhibit 10.26 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No.
1-03876).
First Amended and Restated Pipeline Delivery, Tankage and Loading Rack Throughput Agreement (El Dorado), dated
November 11, 2011, between Frontier El Dorado Refining LLC and El Dorado Logistics LLC (incorporated by reference
to Exhibit 10.27 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2011, File No.
1-03876).
Seventh Amended and Restated Omnibus Agreement, dated July 12, 2012, among HollyFrontier Corporation, Holly
Energy Partners, L.P. and certain of their respective subsidiaries (incorporated by reference to Exhibit 10.3 to the
Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876).
109
Table of Content
Exhibit
Number
10.30
10.31
10.32
10.33
10.34
10.35
Description
Lease and Access Agreement (Cheyenne), dated November 9, 2011, between Frontier Refining LLC and Cheyenne
Logistics LLC (incorporated by reference to Exhibit 10.5 of Registrant's Current Report on Form 8-K filed November
10, 2011, File No. 1-03876).
Lease and Access Agreement (El Dorado), dated November 9, 2011, between Frontier El Dorado Refining LLC and
El Dorado Logistics LLC (incorporated by reference to Exhibit 10.6 of Registrant's Current Report on Form 8-K filed
November 10, 2011, File No. 1-03876).
Credit Agreement, dated July 1, 2011, among HollyFrontier Corporation and certain of its subsidiaries, as borrowers,
Union Bank, N.A., as administrative agent and certain lenders from time to time party thereto (incorporated by reference
to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed July 8, 2011, File No. 1-03876).
First Amendment to Credit Agreement, dated August 24, 2011, among HollyFrontier Corporation and certain of its
subsidiaries, as borrowers, Union Bank, N.A, as administrative agent and certain lenders from time to time party thereto
(incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed August 30, 2011, File No.
1-03876).
Guarantee and Collateral Agreement, dated July 1, 2011, among HollyFrontier Corporation and certain of its subsidiaries
in favor of Union Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 of Registrant's Current
Report on Form 8-K filed July 8, 2011, File No. 1-03876).
Frontier Products Offtake Agreement El Dorado Refinery, dated October 19, 1999, between Frontier Oil and Refining
Company and Equiva Trading Company (now Shell Oil Products US, assignee of Equiva Trading Company) (“the
Agreement”) and First Amendment to the Agreement dated September 18, 2000, Second Amendment to the Agreement
dated September 21, 2000, Third Amendment to the Agreement dated December 19, 2000, Fourth Amendment to the
Agreement dated February 22, 2001, Fifth Amendment to the Agreement dated August 14, 2001, Sixth Amendment
to the Agreement dated November 5, 2001, Seventh Amendment to the Agreement dated April 22, 2002, Eighth
Amendment to the Agreement date d May 30, 2003, Ninth Amendment to the Agreement dated May 25, 2004, Tenth
Amendment to the Agreement dated May 3, 2005, Eleventh Amendment to the Agreement dated March 31, 2006,
Twelfth Amendment to the Agreement dated May 11, 2006, Thirteenth Amendment to the Agreement dated September
30, 2007, Fourteenth Amendment to the Agreement dated May 1, 2008 and Fifteenth Amendment to the Agreement
dated May 28, 2008 (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2008, File No. 1-07627).
10.36
Sixteenth Amendment dated November 1, 2009, to the Frontier Products Offtake Agreement El Dorado Refinery, dated
October 19, 1999, between Frontier Oil and Refining Company and Equiva Trading Company (now Shell Oil Products
US, assignee of Equiva Trading Company) (incorporated by reference to Exhibit 10.14 to Frontier Oil Corporation's
Annual Report on Form 10-K for its fiscal year ended December 31, 2009, File No. 1-07627).
10.37 Master Crude Oil Purchase and Sale Contract, dated November 1, 2010, among BNP Paribas Energy Trading GP, BNP
Paribas Energy Trading Canada Corp., Frontier Oil and Refining Company and Frontier Oil Corporation (incorporated
by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly Report on Form 10-Q for the quarterly period
ended September 30, 2010, File No. 1-07627).
10.38
10.39
10.40
10.41
Guaranty, dated November 1, 2010, by Frontier Oil Corporation in favor of BNP Paribas Energy Trading GP and BNP
Paribas Energy Trading Canada Corp. (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Quarterly
Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 1-07627).
LLC Interest Purchase Agreement, dated July 12, 2012, among HollyFrontier Corporation, Holly Energy Partners, L.P.
and HEP UNEV Holdings LLC (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2012, File No. 1-03876).
Limited Partial Waiver of Incentive Distribution Rights under the First Amended and Restated Agreement of Limited
Partnership of Holly Energy Partners, L.P., dated July 12, 2012 (incorporated by reference to Exhibit 10.4 to the
Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, File No. 1-03876).
Amended and Restated Limited Liability Company Agreement of HEP UNEV Holdings LLC, dated July 12, 2012,
among HEP UNEV Holdings LLC, HollyFrontier Holdings LLC and Holly Energy Partners, L.P. (incorporated by
reference to Exhibit 10.5 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30,
2012, File No. 1-03876).
10.42+ Holly Corporation Stock Option Plan as adopted at the Annual Meeting of Stockholders of Holly Corporation on
December 13, 1990 (incorporated by reference to Exhibit 4(i) of Registrant's Annual Report on Form 10-K for its fiscal
year ended July 31, 1991, File No. 1-03876).
110
Table of Content
Exhibit
Number
Description
10.43+ HollyFrontier Corporation Long-Term Incentive Compensation Plan (formerly the Holly Corporation Long-Term
Incentive Compensation Plan), as amended and restated on May 24, 2007 as approved at the Annual Meeting of
Stockholders of Holly Corporation on May 24, 2007 (incorporated by reference to Exhibit 10.4 of Registrant's Annual
Report on Form 10-K for its fiscal year ended December 31, 2008, File No. 1-03876).
10.44+
First Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by reference
to Exhibit 10.5 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2008, File No.
1-03876).
10.45+
Second Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by
reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed May 18, 2011, File No. 1-03876).
10.46+ Third Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by
reference to Exhibit 4.6 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No.
333-184877).
10.47+ Holly Corporation – Supplemental Payment Agreement for 2001 Service as Director (incorporated by reference to
Exhibit 10.19 of Registrant's Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-03876).
10.48+ Holly Corporation – Supplemental Payment Agreement for 2002 Service as Director (incorporated by reference to
Exhibit 10.20 of Registrant's Annual Report on Form 10-K for its fiscal year ended July 31, 2002, File No. 1-03876).
10.49+ Holly Corporation – Supplemental Payment Agreement for 2003 Service as Director (incorporated by reference to
Exhibit 10.2 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended January 31, 2003, File No.
1-03876).
10.50+ Holly Corporation Amended and Restated Change in Control Agreement Policy (incorporated by reference to Exhibit
10.1 of Registrant's Current Report on Form 8-K filed March 1, 2011, File No. 1-03876).
10.51+ Holly Corporation Employee Form of Change in Control Agreement (for grandfathered Holly Corporation employees)
(incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed February 20, 2008, File
No. 1-03876).
10.52+ HollyFrontier Corporation Form of Change in Control Agreement (for legacy Frontier Oil Corporation executives)
(incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed February 24, 2012, File
No. 1-03876).
10.53+ HollyFrontier Corporation Form of Amendment to Change in Control Agreement for Chief Executive Officer and
Chief Financial Officer (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed
May 10, 2012, File No. 1-03876).
10.54+ HollyFrontier Corporation Form of Change in Control Agreement (for legacy Holly Corporation employees)
(incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed March 30, 2012, File No.
1-03876).
10.55+ HollyFrontier Corporation Form of Change in Control Agreement (for HollyFrontier Corporation new hires and
promotes) (incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed March 30, 2012,
File No. 1-03876).
10.56+
Form of Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly
Report on Form 10-Q for the quarterly period ended March 31, 2009, File No. 1-03876).
10.57+
Form of Executive Restricted Stock Agreement [time and performance based vesting] (incorporated by reference to
Exhibit 10.7 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No.
1-03876).
10.58+
Form of Employee Restricted Stock Agreement [time based vesting] (incorporated by reference to Exhibit 10.10 of
Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010, File No. 1-03876).
10.59+
Form of Performance Share Unit Agreement (for 162(m) covered employees) (incorporated by reference to Exhibit
4.11 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).
10.60+
Form of Performance Share Unit Agreement (for non-162(m) covered employees) (incorporated by reference to Exhibit
4.12 of the Registrant's Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).
111
Table of Content
Exhibit
Number
10.61+
10.62+
Description
Form of Restricted Stock Agreement (time-based vesting) (incorporated by reference to Exhibit 4.13 of the Registrant's
Registration Statement on Form S-8 filed November 9, 2012, File No. 333-184877).
Form of Notice of Grant of Restricted Stock (incorporated by reference to Exhibit 4.14 of the Registrant's Registration
Statement on Form S-8 filed November 9, 2012, File No. 333-184877).
10.63+* Form of Restricted Stock Unit Agreement (for non-employee directors).
10.64+* Form of Notice of Grant of Restricted Stock Units (for non-employee directors).
10.65+ Waiver Agreement, dated February 21, 2011, between Holly Corporation and Matthew P. Clifton thereto (incorporated
by reference to Exhibit 10.9 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31,
2011, File No. 1-03876).
10.66+ Waiver Agreement, dated February 21, 2011, between Holly Corporation and Bruce R. Shaw (incorporated by reference
to Exhibit 10.10 of Registrant's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2011, File
No. 1-03876).
10.67+
10.68+
10.69+
10.70+
10.71+
10.72+
Form of Indemnification Agreement entered into with directors and officers of Holly Corporation (incorporated by
reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed December 13, 2006, File No. 1-03876).
Retention and Assumption Agreement, dated February 21, 2011, among Frontier Oil Corporation, Holly Corporation
and Michael C. Jennings (incorporated by reference to Exhibit 10.1 to Frontier Oil Corporation's Current Report on
Form 8-K filed February 21, 2011, File No. 1-07627).
Retention and Assumption Agreement, dated February 21, 2011, among Frontier Oil Corporation, Holly Corporation
and Doug S. Aron (incorporated by reference to Exhibit 10.2 to Frontier Oil Corporation's Current Report on Form 8-
K filed February 21, 2011, File No. 1-07627).
HollyFrontier Corporation Omnibus Incentive Compensation Plan (formerly the Frontier Oil Corporation Omnibus
Incentive Compensation Plan) (incorporated by reference to Exhibit 10.5 of Registrant's Current Report on Form 8-K
filed July 8, 2011, File No. 1-03876).
Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Stock Unit Agreement with Double Trigger
Vesting (incorporated by reference to Exhibit 10.15 of Registrant's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2011, File No. 1-03876).
Form of Frontier Oil Corporation Omnibus Incentive Compensation Plan Restricted Stock Agreement with Double
Trigger Vesting (incorporated by reference to Exhibit 10.16 of Registrant's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2011, File No. 1-03876).
10.73+* HollyFrontier Corporation Executive Nonqualified Deferred Compensation Plan (formerly the Frontier Deferred
Compensation Plan).
10.74+
10.75+
Form of Indemnification Agreement between Frontier and each of its officers and directors (incorporated by reference
to Exhibit 10.41 to Frontier Oil Corporation's Annual Report on Form 10-K for its fiscal year ended December 31,
2006, File No. 1-07627).
Form of Indemnification Agreement between HollyFrontier Corporation and each of its officers and directors
(incorporated by reference to Exhibit 10.79 of Registrant's Annual Report on Form 10-K for its fiscal year ended
December 31, 2011, File No. 1-03876).
21.1*
Subsidiaries of Registrant.
23.1*
Consent of Independent Registered Public Accounting Firm.
31.1*
Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
112
Table of Content
Exhibit
Number
Description
32.1** Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2** Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
101++
The following financial information from Registrant's Annual Report on Form 10-K for its fiscal year ended December
31, 2012, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii)
Consolidated Statements of Income, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated
Statements of Cash Flows, (v) Consolidated Statements of Equity, and (vi) Notes to the Consolidated Financial
Statements.
* Filed herewith.
** Furnished herewith.
+ Constitutes management contracts or compensatory plans or arrangements.
++ Filed electronically herewith.
113
I, Michael C. Jennings, certify that:
CERTIFICATION
Exhibit 31.1
1.
I have reviewed this annual report on Form 10-K of HollyFrontier Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b. designed such internal control over financial reporting, or caused such internal control over financial reporting
to be designed under our supervision, 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;
c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons
performing the equivalent functions):
a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize
and report financial information; and
b. any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting
Date: February 27, 2013
/s/ Michael C. Jennings
Michael C. Jennings
Chief Executive Officer and President
I, Douglas S. Aron, certify that:
CERTIFICATION
Exhibit 31.2
1.
I have reviewed this annual report on Form 10-K of HollyFrontier Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b. designed such internal control over financial reporting, or caused such internal control over financial reporting
to be designed under our supervision, 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;
c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant's most recent fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal
control over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons
performing the equivalent functions):
a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize
and report financial information; and
b. any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 27, 2013
/s/ Douglas S. Aron
Douglas S. Aron
Executive Vice President and Chief Financial
Officer
CERTIFICATION OF CHIEF EXECUTIVE
OFFICER UNDER SECTION 906 OF THE
SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350
Exhibit 32.1
In connection with the accompanying report on Form 10-K for the period ending December 31, 2012 and filed with the
Securities and Exchange Commission on the date hereof (the “Report”), I, Michael C. Jennings, Chief Executive Officer of
HollyFrontier Corporation (the “Company”) hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002, that to my knowledge:
1. The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act
of 1934, as amended; and
2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
Date: February 27, 2013
/s/ Michael C. Jennings
Michael C. Jennings
Chief Executive Officer and President
CERTIFICATION OF CHIEF FINANCIAL
OFFICER UNDER SECTION 906 OF THE
SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350
Exhibit 32.2
In connection with the accompanying report on Form 10-K for the period ending December 31, 2012 and filed with the
Securities and Exchange Commission on the date hereof (the “Report”), I, Douglas S. Aron, Chief Financial Officer of HollyFrontier
Corporation (the “Company”) hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, that to my knowledge:
1. The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act
of 1934, as amended; and
2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
Date: February 27, 2013
/s/ Douglas S. Aron
Douglas S. Aron
Executive Vice President and Chief Financial
Officer
corPorAte iNforMAtioN
C o r P o r at e o f f iCe r s
Michael C. Jennings
Chief Executive Officer and President
Doug S. Aron
Executive Vice President and Chief Financial Officer
David L. Lamp
Executive Vice President and Chief Operating Officer
George J. Damiris
Senior Vice President, Supply and Marketing
James M. Stump
Senior Vice President, Refining Operations
Denise C. McWatters
Senior Vice President and General Counsel
J.W. Gann Jr.
Vice President, Controller and Chief Accounting Officer
b o a r d o f d i r e C t o r s
Michael C. Jennings
Chairman of the Board
Douglas Y. Bech
Buford P. Berry
Leldon E. Echols
R. Kevin Hardage
Robert J. Kostelnik
James H. Lee
Robert. G. McKenzie
Franklin Myers
Michael E. Rose
Tommy A. Valenta
C o r P o r at e of f i C e
HollyFrontier Corporation
2828 North Harwood, Suite 1300
Dallas, TX 75201-1507
214.871.3555
www.hollyfrontier.com
a u d i t o r s
Ernst & Young LLP
Dallas, Texas
s t o C k e X C h a n g e l i s t in g
New York Stock Exchange
Ticker Symbol: HFC
s t o C k t r a n sf e r a g en t a nd r e g i s t r a r
Wells Fargo Shareowner Services
1110 Centre Point Curve, Suite 101
Mendota Heights, MN 55120
1.800.468.9716
www.shareownerline.com
Correspondence or questions concerning share holdings,
transfers, lost certificates, dividends, or address or
registration changes should be directed to Wells Fargo
Shareowner Services.
a nnua l m e e t in g
The Annual Meeting of Stockholders will be held
at 8:30 a.m. on May 15, 2013, at 2501 North Harwood,
Suite 1900, Dallas, Texas.
s e C f i l in g s
A direct link to the filings of HollyFrontier Corporation
at the U.S. Securities and Exchange Commission website
is available on the HollyFrontier Corporation website at
www.hollyfrontier.com on the Investor Relations page.
s t o Ck P e r f o r m a nCe
Set forth is a line graph comparing, for the period commencing January 1, 2008
and ending December 31, 2012, the annual percentage change in cumulative total
stockholder return on our common stock to the cumulative total stockholder return
of the S&P Composite 500 Stock Index and an industry peer group chosen by
the Company. The stock price performance depicted in the following graph is not
necessarily indicative of future price performance. The graph will not be deemed to
be incorporated by reference in any filing by the Company under the Securities Act
of 1933 or the Securities Exchange of 1934, except to the extent that the Company
specifically incorporates such graph by reference.
HollyFrontier
S&P 500 Index
Old Peer Group
New Peer Group
$200
$150
$100
$50
$0
2007
2008
2009
2010
HollyFrontier
S&P 500 Index
Old Peer Group
100
100
100
New Peer Group
100
37
63
35
31
53
80
28
26
86
92
40
36
2011
103
94
42
34
2012
223
109
74
60
(1) The amounts shown assume that the value of the investment in HollyFrontier and
each index was $100 on January 1, 2008 and that all dividends were reinvested.
(2) The Old Peer Group consists of Alon USA Energy, Inc., CVR Energy, Inc., Delek
US Holdings, Inc., Sunoco Inc. (included through 10/4/2012), Tesoro Corporation,
Valero Energy Corporation and Western Refining, Inc. Sunoco Inc. was acquired
by Energy Transfer Partners, L.P. in October 2012.
(3) The New Peer Group consists of Alon USA Energy, Inc., Delek US Holdings, Inc.,
Marathon Petroleum Corporation (included from 6/23/2011), Phillips 66 Corporation
(included from 4/12/2012), Tesoro Corporation, Valero Energy Corporation and
Western Refining, Inc. Marathon Petroleum Corporation and Phillips 66 Corporation
became public in June 2011 and April 2012, respectively.
2828 North Harwood
Suite 1300
Dallas, Texas 75201-1507