T
R
O
P
E
R
L
A
U
N
N
A
T
N
E
N
I
T
N
O
C
-
D
I
M
T
S
E
W
H
T
U
O
S
N
I
A
T
N
U
O
M
Y
K
C
O
R
EL DORADO REFINERY
• Located in El Dorado, Kansas
• 135,000 BPSD capacity
• Processes sour and heavy Canadian crude oils into high-value light products
• Distributes to high-margin markets in Colorado and Mid-Continent/Plains states
TULSA REFINERY
• Located in Tulsa, Oklahoma
• 125,000 BPSD capacity
• Processes predominantly sweet crude oil with up to 10,000 BPD
of heavy Canadian crudes
• Distributes to the Mid-Continent states
NAVAJO REFINERY
• Located in Artesia, New Mexico, and operated in conjunction with
a refining facility 65 miles east in Lovington, New Mexico
• 100,000 BPSD capacity
• Processes sour crude oil into high-value light products
• Distributes to high-margin markets in Arizona, New Mexico and West Texas
CHEYENNE REFINERY
• Located in Cheyenne, Wyoming
• 52,000 BPSD capacity
• Processes sour and heavy Canadian crude oils into high-value light products
• Distributes to high-margin Eastern Rockies and Plains states
WOODS CROSS REFINERY
• Located in Woods Cross, Utah (near Salt Lake City)
• 45,000 BPSD capacity
• Processes regional sweet and advantaged waxy crude as well as
Canadian sour crude oils
• Distributes to high-margin markets in Utah, Idaho, Nevada, Wyoming
and eastern Washington
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.
• Approximately 3,400 miles of crude oil and petroleum product pipelines
• 14 million barrels of refined product and crude oil storage
• 8 terminals and 7 loading rack facilities
• Refinery processing units in Woods Cross, Utah and El Dorado, Kansas
Mid-Continent
Sales of Refinery
Produced Products
261,200 BPD
The Mid-Continent
Region comprises our
El Dorado and Tulsa
refineries and has a
combined crude oil
processing capacity
of 260,000 BPSD.
Southwest
Sales of Refinery
Produced Products
108,280 BPD
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.
Rocky Mountain
Sales of Refinery
Produced Products
65,940 BPD
The Rocky Mountain
Region comprises our
Cheyenne and Woods
Cross refineries and has
a combined crude oil
processing capacity of
97,000 BPSD.
Crude and
Feedstocks
• Sweet crude oil 58%
• Sour crude oil 18%
• Heavy sour
crude oil 17%
• Other feedstocks
and blends 7%
Crude and
Feedstocks
• Sweet crude oil 28%
• Sour crude oil 63%
• Other feedstocks
and blends 9%
Crude and
Feedstocks
• Sweet crude oil 39%
• Heavy sour
crude oil 35%
• Black wax
crude oil 18%
• Other feedstocks
and blends 8%
Product Mix
• Gasoline 50%
• Diesel fuels 33%
• Jet fuels 7%
• Other 3%
• Lubricants 5%
• Asphalt 2%
Product Mix
• Gasoline 54%
• Diesel fuels 40%
• Other 5%
• Asphalt 1%
Product Mix
• Gasoline 60%
• Diesel fuels 33%
• Other 4%
• Asphalt 3%
• 75% joint-venture interest in the UNEV Pipeline –
• 50% joint-venture interest in the Osage Pipeline –
a 427-mile refined products pipeline system
connecting Salt Lake area refiners to the
Las Vegas product market
• 50% joint-venture interest in the Cheyenne Pipeline –
a 87-mile crude oil pipeline from Fort Laramie,
Wyoming to Cheyenne, Wyoming
• 50% joint-venture interest in the Frontier Pipeline –
a 289-mile crude oil pipeline running from Casper,
Wyoming to Frontier Station, Utah
a 135-mile crude oil pipeline from Cushing, Oklahoma
to El Dorado, Kansas
• 25% joint-venture interest in the SLC Pipeline L.L.C. –
a 95-mile crude oil pipeline system serving refineries
in the Salt Lake City area
Spokane
Boise
Mountain Home
SALT LAKE CITY
PADD IV
Fargo
Casper
Guernsey
Sioux Falls
PADD II
Minneapolis
CHEYENNE
Sidney
Omaha
Des Moines
Denver
Topeka
Kansas City
Chicago
PADD I
Cedar City
EL DORADO
St. Louis
Bloomfield
Phoenix
Tucson
Albuquerque
Roswell
El Paso
Moriarty
ARTESIA
TULSA
Springfield
Rogers
Cushing
Oklahoma City
Duncan
Little Rock
Wichita Falls
Abilene
Orla Midland
PADD III
Houston
PADD V
Las Vegas
Proximity to Growing
North American
Crude Production
All five HFC refineries are
advantageously positioned
near production growth.
Spokane
PADD IV
Boise
Mountain Home
SALT LAKE CITY
PADD V
Las Vegas
Fargo
PADD II
Casper
Minneapolis
Guernsey
Sioux Falls
CHEYENNE
Sidney
Omaha
Des Moines
Denver
Topeka
Kansas City
Cedar City
EL DORADO
St. Louis
Bloomfield
Phoenix
Tucson
Albuquerque
Roswell
El Paso
Moriarty
ARTESIA
TULSA
Springfield
Rogers
Cushing
Oklahoma City
Duncan
Little Rock
Orla Midland
PADD III
Wichita Falls
Abilene
Houston
Chicago
PADD I
PURE-PLAY
COMPETITIVE REFINER
STRONG FINANCIAL
PERFORMANCE
• Five refineries with
• Track record of cash return
457,000 barrels per stream
day refining capacity
to shareholders
• Strong balance sheet
ATTRACTIVE NICHE
PRODUCT MARKETS
WITH ADVANTAGED
CRUDE 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 per
barrel basis
HEP OWNERSHIP
• Stable cash flows from HEP
through quarterly regular
and incentive distributions
• HFC owns 37% of HEP
including the 2% GP interest
• HFC received $105 million in
cash distributions in 2016*
* Q4 2015 through Q3 2016
quarterly LP and GP distributions,
announced and paid in 2016
HOLLYFRONTIER PIPELINES
HEP crude pipelines
HEP crude gathering
HEP product pipeline
HollyFrontier refineries
HFC product markets
Crude hub
HEP terminals
Dear Fellow Shareholders,
2016 was a transformational year for HollyFrontier. We continued to
execute on our business improvement plan while significantly advancing
our strategy to grow and diversify our business. We completed the
Woods Cross Refinery expansion and asset dropdown to Holly Energy
Partners, and announced the largest acquisition in company history
with the addition of our Petro-Canada Lubricants business.
Financial Results Reflect Challenging
Operating Environment
In 2016, we achieved:
• Net income attributable to HFC
stockholders of $82 million (exclud-
ing the non-cash lower of cost or
market “LOCM” adjustment and
asset and goodwill impairments);
• Gross refining margins of $8.38
per produced barrel;
• Operating cash flow of
$602 million; and
• $1.1 billion in cash and short-term
investments as of December 31,
2016, and approximately $991 mil-
lion in long-term debt (exclusive
of HEP debt).
HollyFrontier has a strong balance
sheet and excellent liquidity position.
We are confident that HollyFrontier
remains well positioned to capitalize on
potential future growth opportunities.
2016 Highlights: Key Transactions
and Continued Execution of our
Business Improvement Plan
In 2016, we completed or announced
several key transactions and continued
to execute on our strategies to drive
improvements across our refineries.
Highlights of the year include:
• Transformative acquisition of Petro-
Canada Lubricants Inc.: The Petro-
Canada Lubricants (PCLI) plant,
located in Mississauga, Ontario,
is the largest producer of base oils
in Canada with 15,600 barrels per
day of lubricant production capacity.
PCLI brings HollyFrontier industry
leading product innovation and
R&D capabilities, a global sales force
and distribution network and a strong
globally recognized brand portfolio.
• Completion and dropdown
of Woods Cross Refinery Units:
HollyFrontier completed the drop-
down of the Woods Cross Refinery
Units constructed as part of the
Woods Cross expansion, including
the newly constructed crude, fluid
catalytic cracking and polymeriza-
tion units, for cash consideration
of approximately $275 million.
• Significant progress on our Business
Improvement Plan: We continued to
make investments in our infrastruc-
ture to enhance the capabilities and
efficiency of our refineries, which
have 457,000 barrels per day of
refining capacity. During the year,
our El Dorado Refinery operated
at a record monthly crude rate
of 150,000 barrels per day, and
set an annual crude rate record of
142,500 barrels per day. We believe
we have the opportunity to capture
$565 million of EBITDA in today’s
margin environment. To date, we
have achieved approximately
$300 million of this opportunity
and expect to execute the remaining
$265 million in 2017 and 2018.
Diversification into Lubricants
We are working to further enhance
HollyFrontier’s scale, diversify the
Company’s revenue stream and
expand underappreciated segments
of our business. The PCLI acquisition,
which was completed on February 1,
2017, is a key part of this strategy.
Through the acquisition, we added
significant scale to make lubricants
a more important component of
HollyFrontier’s business profile. We
have been investing in our existing
lubricants capabilities in Tulsa since
2009, and we now anticipate that
lubricants will account for more than
20% of HollyFrontier’s refining earnings
in a normal margin environment, with
an even larger percentage occurring
when refining margins are low.
Our Vision for 2020
In 2016, we developed an aspirational
vision to grow each of our businesses –
refining, midstream and lubricants – by
2020. Our vision takes into account the
challenging market environment and is
based on growing scale and increasing
diversification. In our refining business,
we believe that increasing scale provides
important competitive advantages
in terms of system integration, crude
and feedstock supply and product
synergies, as well as in the acquisition
of talent. In our midstream business,
Holly Energy Partners has a strong
foundation to grow through drop-
downs and external acquisitions,
with a continuing focus on our
existing geography.
2
HollyFrontier Corporation 2016 Annual Report
In addition, we recognize that our people
are central to who we are and what we
do. By investing in our employees, we
are investing in HollyFrontier’s ongoing
success. We are truly thankful for our
2,676 talented employees and all that
they do for HollyFrontier, and with their
help, we will continue to operate safely
and reliably.
Looking Ahead
Moving forward, we are excited about
the opportunities in front of HollyFrontier.
We are making significant progress
executing our Business Improvement
Plan and believe the actions we are
taking through Vision 2020 will enable
us to drive growth, operate even more
safely, efficiently and reliably, and
deliver enhanced value to stockhold-
ers. Petro-Canada Lubricants Inc. adds
diversity to HollyFrontier’s earnings
stream, providing a differentiated
high-margin business that generates
more stable cash flows. We believe
HollyFrontier is well-positioned for
the future with a strong balance sheet,
an excellent liquidity position and an
enhanced platform for growth.
Thank you for your investment
in HollyFrontier.
Sincerely,
George Damiris
Chief Executive Officer and President
The PCLI acquisition represents the
type of opportunities we are pursuing;
it is accretive to earnings, has more
stable cash flows and higher margins,
and is highly complementary to our
refining and midstream businesses.
We are focused on continuing to create
value for shareholders through high-
return growth opportunities such as
the PCLI transaction.
It is important to keep in mind that
HollyFrontier will continue to be disci-
plined in regard to capital allocation
and will be opportunistic in pursuing
value-enhancing, high-return acquisi-
tion opportunities that meet our strict
criteria. Although the current landscape
for refiners remains difficult, we believe
that these actions will position us for
success in the years to come.
Committed to Our Role as a
Responsible Corporate Citizen
HollyFrontier continues to be guided
by our core values of health, safety,
corporate citizenship and environ-
mental stewardship. Some highlights
of our recent social responsibility
initiatives include:
• In 2016, we invested more than
$497 million to enhance and expand
our manufacturing operations,
improve reliability and minimize
our environmental impact.
• The health and safety of our employ-
ees, contractors and communities
is our top priority. A key element of
our reliability initiatives is continuing
to increase safety performance,
and HollyFrontier will never stop
working toward the goal of an injury-
free workplace. In 2016, we decreased
our employee recordable injury rate
by 10% and our process safety Tier 1
incident rate by 43% as compared
to the previous year.
• We strive to be good stewards of our
environment. Since 2011, HollyFrontier
has consistently reduced the amount
of energy required to process a barrel
of crude oil, and we continue to look
for ways to enhance our efficiency.
George J. Damiris
Chief Executive Officer
and President
3
Financial Highlights
YEAR ENDED DECEMBER 31
Sales and other revenues
Income (loss) before income taxes
Net income (loss) attributable to HFC stockholders
Net income (loss) 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
2015
2016
$ 13,237,920,000
$ 10,535,700,000
$
1,208,568,000
$
$
$
$
740,101,000
3.90
979,626,000
676,155,000
$
$
$
$
$
(171,534,000)
(260,453,000)
(1.48)
602,271,000
479,790,000
$ 8,388,299,000
$ 9,435,661,000
$ 5,253,415,000
$ 4,681,394,000
488,350
446,560
2,704
464,980
442,110
2,676
7
2
7
,
1
3
6
6
,
1
6
3
7
0
4
7
1
8
2
)
0
6
2
(
0
8
9
9
6
8
9
5
7
2
0
6
1
9
0
0
2
,
1
6
1
,
0
2
4
6
7
9
1
,
8
3
2
,
3
1
6
3
5
0
1
,
12 13 14 15 16
12 13 14 15 16
12 13 14 15 16
Net Income (Loss)
Attributable to
HFC Stockholders
$ in millions
3
4
4
4
1
4
5
2
4
7
4
4
2
4
4
Cash Flows from
Operating Activities
$ in millions
Revenues
$ in millions
3
5
0
6
,
0
0
0
6
,
4
2
5
,
5
3
5
2
,
5
1
8
6
,
4
7
2
3
0
1
,
6
5
0
0
1
,
0
3
2
,
9
8
8
3
,
8
6
3
4
9
,
12 13 14 15 16
12 13 14 15 16
12 13 14 15 16
Refinery Production
BPD in thousands
HFC Stockholders’ Equity
$ in millions
Total Assets
$ in millions
4
HollyFrontier Corporation 2016 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, 2016
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. Yes
No
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
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 (§229.405 of this chapter) 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 30, 2016, 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 $3.8 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.)
177,360,162 shares of Common Stock, par value $.01 per share, were outstanding on February 17, 2017.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's proxy statement for its annual meeting of stockholders to be held on May 11, 2017, which proxy statement will be filed with the Securities
and Exchange Commission within 120 days after December 31, 2016, 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
PART IV
Signatures
Index to exhibits
2
Page
3
4
6
23
33
34
35
35
36
37
50
50
54
101
101
101
101
101
101
102
102
102
103
104
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. Forward-
looking statements use words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “should,” “would,”
“could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations. 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. All statements concerning our
expectations for future results of operations are based on forecasts for our existing operations and do not include the potential
impact of any future acquisitions. 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, including Petro-Canada Lubricants Inc.;
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 and is used to manufacture tires and industrial rubber
products and in the production of specialty 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 an 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 oil 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 commercial heavy duty engine oils, passenger
car oils and specialty products for industrial applications such as heat transfer, metalworking, rubber and other general process
oil.
“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.
“Reforming” means the process of converting gasoline type molecules into aromatic, higher octane gasoline blend stocks
while producing hydrogen in the process.
“RINs” means renewable identification numbers and refers to serial numbers assigned to credits generated from biodiesel
production under the Environmental Protection Agency’s Renewable Fuel Standard 2 (“RFS2”) regulations that mandate increased
volumes of renewable fuels blended into the nation’s fuel supply. In lieu of blending, refiners may purchase these transferable
credits in order to comply with the regulations.
“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 in the FCC process. 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.
“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 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 SEC filings is available on our website
under the Investor Relations tab. 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.”
As of December 31, 2016, 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 HollyFrontier Asphalt Company (“HFC Asphalt”) which operates various asphalt terminals in
Arizona, New Mexico and Oklahoma;
owned a 37% interest in HEP, which includes our 2% general partner interest.
On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a share purchase agreement with Suncor
Energy Inc. (“Suncor”) to acquire 100% of the outstanding capital stock of Petro-Canada Lubricants Inc. (“PCLI”) that closed on
February 1, 2017. Cash consideration paid was $862.1 million, or $1.125 billion in Canadian dollars.
PCLI is located in Mississauga, Ontario and is the largest producer of base oils in Canada with a plant having 15,600 BPD of
lubricant production capacity, and is the only North American producer of high margin Group III base oils. The facility is downstream
integrated from base oils to finished lubricants and produces a broad spectrum of specialty lubricants and white oils that are
distributed to end customers worldwide. The acquisition brings HollyFrontier industry-leading product innovation and research
and development capabilities, a global sales and distribution network and a strong brand portfolio recognized globally. With this
transaction, we have also acquired a perpetual exclusive license to use the Petro-Canada trademark in association with the lubricant
products. With the addition of PCLI, HollyFrontier becomes the fourth largest lubricants producer in North America with a capacity
of 28,000 BPD, approximately 10% of North American production.
HEP is a consolidated variable interest entity (“VIE”) as defined under U.S. generally accepted accounting principles (“GAAP”).
Information on HEP's assets and acquisitions completed between 2012 and 2016 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
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 HFC Asphalt. The HEP segment involves
all of the operations of HEP. See Note 20 “Segment Information” in the Notes to Consolidated Financial Statements for additional
information on our reportable segments.
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 a combined crude oil processing capacity of 457,000 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 2016, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale)
represented 52%, 35%, 4% 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 non-cash effects of lower of cost or market inventory valuation adjustments and 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 (8)
Refinery operating expenses (9)
Net operating margin (8)
Refinery operating expenses per throughput barrel (10)
Feedstocks:
Sweet crude oil
Sour crude oil
Heavy sour crude oil
Black wax crude oil
Other feedstocks and blends
Total
2016
Years Ended December 31,
2015
2014
423,910
457,480
442,110
435,420
464,980
432,560
463,580
446,560
438,000
488,350
406,180
436,400
425,010
420,990
461,640
92.8%
97.6%
91.7%
$
$
$
58.02
49.64
8.38
5.57
2.81
5.30
$
$
$
48%
26%
16%
3%
7%
100%
71.32
55.25
16.07
5.71
10.36
5.39
$
$
$
51%
25%
15%
2%
7%
100%
110.19
96.21
13.98
6.38
7.60
6.16
53%
23%
15%
2%
7%
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, 2016, our consolidated crude capacity
increased from 443,000 BPSD to 457,000 BPSD upon completion of our Woods Cross Refinery expansion project.
(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.
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(8) Excludes lower of cost or market inventory valuation adjustments that increased refinery gross margin by $291.9 million
for the year ended December 31, 2016 and decreased refinery gross margin by $227.0 million and $397.5 million for the
years ended December 31, 2015 and 2014, respectively.
(9) Represents operating expenses of our refineries, exclusive of depreciation and amortization.
(10) Represents refinery operating expenses, exclusive of depreciation and amortization, divided by refinery throughput.
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
LPG and other
Total
2016
Years Ended December 31,
2015
2014
52%
35%
4%
2%
2%
3%
2%
100%
52%
35%
4%
1%
2%
3%
3%
100%
50%
34%
4%
2%
3%
2%
5%
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.
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 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 22 “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 processing capacity and the
ability to process significant volumes of heavy and sour crudes. The integrated refining processes at the Tulsa West and East
refinery facilities provide us with a highly complex refining operation having a combined crude processing rate of approximately
125,000 barrels per stream day. For 2016, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for
resale) represented 50%, 33%, 7% and 5%, respectively, of our Mid-Continent sales volumes.
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Table of Content
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 (8)
Refinery operating expenses (9)
Net operating margin (8)
Refinery operating expenses per throughput barrel (10)
Mid-Continent Region (El Dorado and Tulsa Refineries)
Feedstocks:
Sweet crude oil
Sour crude oil
Heavy sour crude oil
Other feedstocks and blends
Total
2016
Years Ended December 31,
2015
2014
262,170
280,920
269,840
261,200
285,080
263,340
277,260
266,170
258,420
295,470
243,240
255,020
249,350
245,600
273,630
100.8%
101.3%
93.6%
$
$
$
58.14
50.17
7.97
4.69
3.28
4.36
$
$
$
72.33
56.88
15.45
4.95
10.50
4.61
$
$
$
110.79
98.39
12.40
5.73
6.67
5.52
2016
Years Ended December 31,
2015
2014
58%
18%
17%
7%
100%
59%
21%
15%
5%
100%
71%
11%
14%
4%
100%
Footnote references are provided under our Consolidated Refinery Operating Data table on page 7.
The El Dorado Refinery is located on 1,100 acres south of El Dorado, Kansas and is a fully integrated refinery. The principal
processing 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.
The Tulsa West facility is located on a 750-acre site in Tulsa, Oklahoma situated along the Arkansas River. The principal processing
units at the Tulsa West facility consist of crude and vacuum distillation (with light ends recovery), naphtha hydrodesulfurization,
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.
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.
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. Additionally, HEP's on-site truck and rail racks facilitate access to local
refined product markets.
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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. Our Gulf Coast competitors typically have lower production costs due to greater
economies of scale; however, they incur higher refined product transportation costs, which allows the El Dorado Refinery to
compete effectively in the Plains States and Rocky Mountain region with Gulf Coast refineries.
The Tulsa Refineries 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.
We have an offtake agreement through November 2019 with an affiliate of Sinclair whereby Sinclair purchases 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, 2016, sales to Sinclair represented approximately 26% of the Tulsa Refineries' total sales and 9% 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, truck stop operators 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.
For the year ended December 31, 2016, sales to Shell Oil represented approximately 10% of our Mid-Continent refineries' total
sales and 10% of our total consolidated sales. We have a sales agreement with an affiliate of Shell Oil under which Shell Oil
purchases gasoline and diesel production of the El Dorado Refinery and Tulsa Refineries at market prices through October 2018
primarily to support its branded marketing network.
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 5% of paraffinic oil capacity and 14% of wax production
capacity in the United States market and is one of four refineries of specialty aromatic oils in North America.
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
LPG and other
Total
Years Ended December 31,
2015
2014
2016
50%
33%
7%
1%
2%
5%
2%
100%
50%
33%
7%
1%
2%
4%
3%
100%
47%
33%
7%
1%
3%
4%
5%
100%
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Table of Content
Crude Oil and Feedstock Supplies
Both of our Mid-Continent Refineries are connected via pipeline to Cushing, Oklahoma, a significant crude oil pipeline trading
and storage hub. The El Dorado Refinery and the Tulsa Refineries are located approximately 125 miles and 50 miles, respectively,
from Cushing, Oklahoma. Local pipelines provide direct access to regional Oklahoma crude production as well as access to United
States onshore and Canadian 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. Additionally, we have transportation service agreements
to transport Canadian crude oil on the Spearhead and Keystone Pipelines, enabling us to transport Canadian crude oil to Cushing
for subsequent shipment to either of our Mid-Continent Refineries.
We also purchase isobutane, natural gasoline, butane and other feedstocks for processing at our Mid-Continent Refineries. The El
Dorado Refinery is connected to Conway, Kansas, a major gas liquids trading and storage hub, via the Oneok Pipeline. From time
to time, other feedstocks such gas oil, naphtha and light cycle oil are purchased from other refiners for use at our refineries.
Southwest Region (Navajo Refinery)
Facilities
The Navajo Refinery has a crude oil processing 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 2016, gasoline and diesel fuel (excluding
volumes purchased for resale) represented 54% and 40%, 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 (8)
Refinery operating expenses (9)
Net operating margin (8)
Refinery operating expenses per throughput barrel (10)
Feedstocks:
Sweet crude oil
Sour crude oil
Heavy sour crude oil
Other feedstocks and blends
Total
2016
Years Ended December 31,
2015
2014
98,090
107,690
106,460
108,280
110,740
100,450
111,840
110,210
111,580
119,560
98,120
110,250
107,520
106,870
115,620
98.1%
100.5%
98.1%
$
$
$
57.87
48.68
9.19
4.72
4.47
4.75
$
$
$
28%
63%
—%
9%
100%
69.76
53.57
16.19
4.92
11.27
4.91
$
$
$
36%
54%
—%
10%
100%
110.54
94.58
15.96
5.43
10.53
5.26
13%
74%
2%
11%
100%
Footnote references are provided under our Consolidated Refinery Operating Data table on page 7.
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.
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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. 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, 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 Magellan 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, to Moriarty, New Mexico, near Albuquerque, via HEP's pipelines running from Artesia to
San Juan County, New Mexico, and to Bloomfield, 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 and Moriarty, 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 Cenovus Energy), Valero, Alon
USA, Inc. (“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.
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
pipeline systems deliver 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.
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 2026, and HEP has options to renew for one additional ten-year period. HEP
owns and operates a 12-inch pipeline from the Navajo Refinery to the leased pipeline as well as terminalling facilities in Moriarty,
which is 40 miles east of Albuquerque. This facility permits us to ship light products to the Albuquerque and Santa Fe, New Mexico
areas. In addition, we serve southern Colorado and northern Arizona primarily out of a terminal in Bloomfield, New Mexico,
which is owned by Western Refining.
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
Fuel oil
Asphalt
LPG and other
Total
Years Ended December 31,
2015
2014
2016
54%
40%
3%
1%
2%
100%
55%
39%
2%
1%
3%
100%
54%
38%
4%
1%
3%
100%
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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
and through third-party tank trucks and crude oil pipeline systems for delivery to the Navajo Refinery.
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 refiners for use as
feedstock.
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)
Facilities
The Cheyenne and the Woods Cross Refineries have crude oil processing capacities of 52,000 and 45,000 barrels per stream day,
respectively. 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 2016, gasoline and diesel fuel (excluding volumes purchased for
resale) represented 60% and 33%, respectively, of our Rocky Mountain sales volumes.
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 (8)
Refinery operating expenses (9)
Net operating margin (8)
Refinery operating expenses per throughput barrel (10)
Feedstocks:
Sweet crude oil
Sour crude oil
Heavy sour crude oil
Black wax crude oil
Other feedstocks and blends
Total
2016
Years Ended December 31,
2015
2014
63,650
68,870
65,810
65,940
69,160
68,770
74,480
70,180
68,000
73,320
64,820
71,130
68,140
68,520
72,390
65.6%
82.9%
78.1%
$
$
$
57.80
49.13
8.67
10.45
(1.78)
10.01
$
$
$
39%
—%
35%
18%
8%
100%
70.05
51.80
18.25
9.89
8.36
9.03
$
$
$
42%
—%
37%
13%
8%
100%
107.51
90.95
16.56
10.20
6.36
9.83
44%
2%
30%
15%
9%
100%
Footnote references are provided under our Consolidated Refinery Operating Data table on page 7.
The Cheyenne Refinery facility is located on a 255-acre site and is a fully integrated refinery with crude distillation, vacuum
distillation, coking, FCC, 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.
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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. The facility typically processes
or blends an additional 2,000 BPSD of natural gasoline, butane and gas oil over its 45,000 BPSD capacity.
We have recently curtailed production at the Woods Cross refinery due to insufficient crude supply provided by the Plains Rocky
Mountain Pipeline. We are unable to predict the duration of the supply disruption at this time, but are considering alternative
solutions and working with Plains and others to rectify the situation.
We own and operate 4 miles of hydrogen pipeline that connects the Woods Cross Refinery to a hydrogen plant located on the
property of 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 have completed construction on our existing Woods Cross expansion project, increasing crude processing capacity to 45,000
BPSD, and providing greater crude slate flexibility, which we believe will increase capacity utilization and improve overall
economic returns during periods when wax crudes are in short supply. The project also included construction of new refining
facilities and a new rail loading rack for intermediates and finished products associated with refining waxy crude oil.
On November 18, 2013, the Utah Division of Air Quality issued a revised air quality permit (the “Approval Order”) authorizing
the expansion. On December 18, 2013, two local environmental groups filed an administrative appeal challenging the issuance
of the Approval Order and seeking a stay of the Approval Order. Following an extended appeal process, the Executive Director
of the Utah Department of Environmental Quality issued a final order in favor of Woods Cross on all claims on March 31, 2015,
and dismissed the project opponents’ arguments with prejudice. On April 27, 2015, the opponents filed a petition for review and
notice of appeal with the Utah Court of Appeals challenging the agency’s decision to uphold the permit and dismiss the project
opponents’ arguments. On August 4, 2016, the Utah Court of Appeals transferred the case to the Utah Supreme Court. The Utah
Supreme Court established a supplemental briefing schedule, which ran through October 2016. Oral argument took place on
December 14, 2016 and focused primarily on alleged procedural defects in the Petitioner’s appeal. The Court took the matter under
advisement and will issue a written decision. Our continued use of the expansion project facilities is subject to the Woods Cross
Refinery successfully defending the Approval Order on appeal at the Utah Court of Appeals.
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 directly
from the truck rack at the refinery, therefore, eliminating transportation costs. The Cheyenne Refinery ships refined products via
the Magellan pipeline serving Denver and Colorado Springs, Colorado.
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.
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 into the Woods Cross market via the Pioneer Pipeline include Sinclair, ExxonMobil, CHS and Phillips 66. We
estimate the four local refineries that compete with our Woods Cross Refinery have a combined capacity to process approximately
165,000 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.
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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 a common carrier pipeline system owned by Tesoro Logistics
Northwest Pipelines LLC (“Tesoro Logistics”) to numerous terminals, including HEP's terminal at Spokane, Washington and to
terminals at Pocatello and Boise, Idaho and Pasco, Washington that are owned by Tesoro Logistics. We sell to branded and
unbranded customers in these markets. In 2012, we began shipping refined products to Cedar City, Utah and 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
Fuel oil
Asphalt
LPG and other
Total
Years Ended December 31,
2015
2014
2016
60%
33%
2%
3%
2%
100%
57%
36%
3%
2%
2%
100%
56%
33%
1%
5%
5%
100%
Crude Oil and Feedstock Supplies
Crude oil is transported to the Cheyenne Refinery from suppliers in Canada, Colorado, Nebraska, North Dakota and Montana via
common carrier pipelines owned by Spectra, Plains 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. We also receive 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.
HollyFrontier Asphalt Company
We manufacture commodity and modified asphalt products at our manufacturing facilities located in Glendale, Arizona;
Albuquerque, New Mexico; Artesia, New Mexico and Catoosa, Oklahoma. 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 Catoosa facility manufactures specialty modified asphalt and commodity asphalt products. We
market these asphalt products in Arizona, New Mexico, Oklahoma, Kansas, Missouri, Texas and northern Mexico. Our products
are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and
government projects.
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 owns
and operates logistic assets consisting of petroleum product and crude oil pipelines, terminals, tankage, loading rack facilities and
refinery processing units that principally support our refining and marketing operations in the Mid-Continent, Southwest and
Rocky Mountain regions of the United States and Alon's refinery in Big Spring, Texas. Additionally, HEP owns a 75% interest in
UNEV Pipeline, LLC (“UNEV”), the owner of a pipeline running from Woods Cross, Utah to Las Vegas, Nevada (the “UNEV
Pipeline”) and associated product terminals; a 50% interest in Frontier Aspen LLC, the owner of a pipeline running from Wyoming
to Frontier Station, Utah (the “Frontier Pipeline”); a 50% interest in Osage Pipe Line Company, LLC, the owner of a pipeline
running from Cushing, Oklahoma to El Dorado, Kansas (the “Osage Pipeline”); a 50% interest in Cheyenne Pipeline, LLC, the
owner of a pipeline running from Fort Laramie, Wyoming to Cheyenne, Wyoming (the “Cheyenne Pipeline”); and a 25% interest
in SLC Pipeline, LLC, the owner of a pipeline (the “SLC Pipeline”) that serves refineries in the Salt Lake City, Utah area.
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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 and storing refined products and other hydrocarbons and
providing other services at its storage tanks, terminals and refinery processing units. HEP does not take ownership of products
that it transports, terminals, stores or refines; therefore, it is not directly exposed to changes in commodity prices.
HEP's recent acquisitions (2012 through present) are summarized below:
Woods Cross Assets
On October 3, 2016, HEP acquired from us all the membership interests of Woods Cross Operating LLC, which owns the crude
unit, FCCU and polymerization unit of the first phase of our Woods Cross Refinery expansion project that was completed in the
second quarter of 2016, for cash consideration of approximately $278.0 million. In connection with this transaction, we entered
into 15-year tolling agreements containing minimum quarterly throughput commitments that provide minimum annualized
payments to HEP of $56.7 million.
Cheyenne Pipeline
On June 3, 2016, HEP acquired a 50% interest in Cheyenne Pipeline LLC, owner of the Cheyenne Pipeline, in exchange for a
contribution of $42.6 million in cash to Cheyenne Pipeline LLC. Cheyenne Pipeline will continue to be operated by an affiliate
of Plains All American Pipeline, L.P. (“Plains”), which owns the remaining 50% interest. The 87-mile crude oil pipeline runs from
Fort Laramie, Wyoming to Cheyenne, Wyoming and has an 80,000 BPD capacity.
Tulsa Tanks
On March 31, 2016, HEP acquired crude oil tanks located at our Tulsa Refineries from Plains for $39.5 million. Previously in
2009, we sold these tanks to Plains and leased them back, and due to our continuing interest in the tanks, we accounted for the
transaction as a financing arrangement. Accordingly, the tanks remained on our balance sheet and were depreciated for accounting
purposes, and the proceeds received from Plains were recorded as a financing obligation and presented as a component of
outstanding debt.
In accounting for HEP’s March 2016 purchase from Plains, the amount paid was recorded against our outstanding financing
obligation balance of $30.8 million, with the excess $8.7 million payment resulting in a loss on early extinguishment of debt.
Magellan Asset Exchange
On February 22, 2016, we obtained a 50% membership interest in Osage Pipe Line Company, LLC (“Osage”) in exchange for a
20-year terminalling services agreement, whereby, a subsidiary of Magellan Midstream Partners (“Magellan Midstream”) will
provide terminalling services for all of our products originating in Artesia, New Mexico that require terminalling in or through El
Paso, Texas. Under the agreement, we will be charged tariffs based on the volumes of refined product processed. Osage is the
owner of the Osage pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to our El Dorado Refinery in
Kansas and also has a connection to the Jayhawk pipeline that services the CHS refinery in McPherson, Kansas. The Osage pipeline
is the primary pipeline that supplies our El Dorado Refinery with crude oil.
Also on February 22, 2016, we contributed the 50% membership interest in Osage to HEP, and in exchange received HEP's El
Paso terminal. Pursuant to this exchange, HEP agreed to build two connections to Magellan Midstream's El Paso terminal. In
addition, HEP agreed to become operator of the Osage Pipeline.
El Dorado Asset Transaction
On November 1, 2015, HEP acquired from us newly constructed naphtha fractionation and hydrogen generation units at our El
Dorado Refinery for cash consideration of $62.0 million. In connection with this transaction, we entered into 15-year tolling
agreements containing minimum quarterly throughput commitments that provide minimum annualized payments to HEP of $15.1
million.
Frontier Pipeline Transaction
On August 31, 2015, HEP purchased a 50% interest in Frontier Aspen LLC (previously known as Frontier Pipeline Company),
owner of the Frontier Pipeline, from an affiliate of Enbridge, Inc. for $55.0 million. Frontier Pipeline will continue to be operated
by an affiliate of Plains, which owns the remaining 50% interest. The 289-mile crude oil pipeline runs from Casper, Wyoming to
Frontier Station, Utah and has a 72,000 BPD capacity, and supplies Canadian and Rocky Mountain crudes to Salt Lake City area
refiners through a connection to the SLC Pipeline.
Crude Tank Farm Asset Transaction
On March 6, 2015, HEP purchased an existing crude tank farm adjacent to our El Dorado Refinery from an unrelated third-party
for $27.5 million in cash. We are the main customer of this crude tank farm.
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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.
Transportation Agreements
Agreements with HEP
HEP serves our refineries under long-term pipeline, terminal and tankage throughput agreements and refinery processing tolling
agreements expiring from 2019 through 2036. Under these agreements, we pay HEP fees to transport, store and process throughput
volumes of refined products, crude oil and feedstocks on HEP's pipelines, terminals, tankage, loading rack facilities and refinery
processing units 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 index. As of December 31, 2016,
these agreements result in minimum annualized payments to HEP of $321.0 million.
Our transactions with HEP including the transactions discussed above and fees paid under our transportation agreements with
HEP and UNEV 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, 2016, 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;
two 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;
one 65-mile intermediate pipeline that is used for the shipment of crude oil from the gathering systems in Barnsdall and
Beeson, New Mexico to our Navajo Refinery.
approximately 940 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and
Oklahoma that primarily deliver crude oil to our Navajo Refinery;
approximately 8 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 our Tulsa East and Tulsa West facilities;
crude receiving assets located at our Cheyenne Refinery;
a 75% interest in the UNEV Pipeline, a 427-mile, 12-inch refined products pipeline running from Woods Cross, Utah to
Las Vegas, Nevada;
a 50% interest in the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to our El
Dorado Refinery and also has a connection to the Jayhawk pipeline that services the CHS refinery in McPherson, Kansas;
a 50% interest in the Cheyenne Pipeline, an 87-mile crude oil pipeline running from Fort Laramie, Wyoming to Cheyenne,
Wyoming;
a 50% interest in the Frontier Pipeline, a 289-mile crude oil pipeline running from Casper, Wyoming to Frontier Station,
Utah through a connection to the SLC Pipeline; and
a 25% interest in the SLC Pipeline, a 95-mile intrastate crude oil pipeline system that transports crude oil into the Salt
Lake City, Utah area from the Utah terminus of the Frontier Pipeline, as well as crude oil flowing from Wyoming and
Utah via Plains Rocky Mountain Pipeline.
•
•
•
•
•
•
•
•
•
•
•
•
•
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Refined Product Terminals and Refinery Tankage
•
•
•
•
•
•
•
•
•
•
three refined product terminals located in Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate
capacity of approximately 600,000 barrels, that are integrated with HEP's refined product pipeline system that serves our
Navajo Refinery;
one refined product terminal located in Spokane, Washington, with a capacity of approximately 400,000 barrels, that serves
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 units located at our Cheyenne
Refinery;
on-site crude oil tankage at our Tulsa, El Dorado, Navajo, Cheyenne and Woods Cross Refineries having an aggregate
storage capacity of approximately 1,350,000 barrels;
on-site refined and intermediate product tankage at our El Dorado, Tulsa and Cheyenne Refineries having an aggregate
storage capacity of approximately 8,800,000 barrels;
eleven crude oil tanks adjacent to our El Dorado Refinery with a capacity of approximately 1,200,000 barrels that primarily
serve our El Dorado Refinery;
a 75% interest in UNEV Pipeline's product terminals near Cedar City, Utah and Las Vegas, Nevada with an aggregate
capacity of approximately 615,000 barrels; and
a 50% interest in Frontier Pipeline's tankage with an aggregate capacity of approximately 72,000 barrels.
Refinery Processing Units
•
•
•
a naphtha fractionation tower at our El Dorado Refinery, with a capacity of 50,000 BPD of desulfurized naphtha;
a hydrogen generation unit at our El Dorado Refinery, with a capacity of 6.1 million standard cubic feet per day of natural
gas.
a crude unit, which is primarily an atmospheric distillation tower, a desalter and heat exchangers, at our Woods Cross
Refinery, with a feedstock capacity of 15,000 BPD of crude oil;
• An FCC unit at our Woods Cross Refinery, which converts crude oil to high-value refined products such as gasoline, diesel
•
and liquefied petroleum gases, with a capacity of 8,000 BPD; and
a polymerization unit at our Woods Cross Refinery, that uses the output of the fluid cracking unit and converts them into
gasoline blendstock, with a capacity of 2,500 BPD.
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, 2016, we had 2,676 employees, of which 908 are currently covered by collective bargaining agreements
having various expiration dates between 2017 and 2020. We consider our employee relations to be good.
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Environmental Regulation
Refinery and pipeline operations are subject to numerous federal, state, provincial and local laws regulating the discharge of
substances into the environment or otherwise relating to the protection of the environment. Permits or other authorizations are
required under these laws for the operation of our refineries, pipelines and related facilities, which can result in the imposition of
costly reporting and maintenance obligations, and these permits and authorizations are subject to revocation, modification and
renewal. Over the years, there have been ongoing communications, including notices of violations, about environmental matters
between us and governmental 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 our operations, and our capital requirements.
Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and
criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital
expenditures; the occurrence of delays in the permitting, development or expansion of projects, and the issuance of injunctive
relief limiting or prohibiting certain operations. The following is a description of the principal environmental laws applicable to
our operations.
Clean Air Act - 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. Also, in October 2015, the EPA lowered the National Ambient Air Quality Standard
(“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. State implementation
of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and
result in increased expenditures for pollution control equipment, the costs of which could be significant. Also, in February 2016,
a new EPA rule became effective that amends three refinery standards already in effect, imposing additional or, in some cases,
new emission control requirements on subject refineries. The final rule requires, among other things, benzene monitoring at the
refinery fence line and submittal of fence line monitoring data to the EPA on a quarterly basis; upgraded storage tank controls
requirements, including new applicability thresholds; enhanced performance requirements for flares, continuous monitoring of
flares and pressure release devices and analysis and remedy of flare release events; and compliance with emissions standards for
delayed coking units. Refineries have up to three years from the effective date of the final rule to come into compliance with
certain requirements of the rule, such as the performance requirements for flares, while other aspects of the rule require compliance
to be achieved at a sooner date. In July 2016, the EPA issued a final rule providing refiners an additional 18 months to comply
with a small subset of the rules related to air emissions resulting from startup, shutdown and maintenance events. More recently,
in December 2016, the EPA granted petitions for reconsideration from industry and environmental organizations on aspects of the
rule related to work practice standards for certain process units and equipment, as well as fence line monitoring requirements. To
date, EPA has not published revised rules. These new rules, as well as subsequent rulemaking under the CAA or similar laws, or
new agency interpretations of existing laws and regulations, may necessitate additional expenditures in future years and result in
increased costs on our operations.
Fuel Quality Regulation - Also, we are subject to the EPA's Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”)
regulations that impose reductions in the benzene content of our produced gasoline. Our refineries currently purchase a portion
of their benzene credits to meet these requirements. If economically justified or otherwise determined to be beneficial, 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 (“EISA”) prescribe certain percentages of
renewable fuels (e.g., ethanol and biofuels) that, where required, must be blended into our produced gasoline and diesel. The
Renewable Fuel Standard 2 (“RFS2”) regulations, finalized by the EPA in 2010 to implement the EISA, requires that most refiners
blend increasing amounts of biofuels with refined products through 2022. Because the EISA requires specified volumes of biofuels,
if the demand for motor fuels decreases in future years, even higher percentages of biofuels may be required. Alternatively, credits
called Renewable Identification Numbers (“RINs”) can be used instead of physically blending biofuels. The price of RINS has
been subject to extreme volatility over the years and costs to purchase RINs can be significant.
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In November 2016, the EPA issued final volume requirements and associated percentage standards under the RFS2 for cellulosic
biofuel, advanced biofuel, and total renewable fuel for 2017 and the biomass-based diesel requirement for 2018. The final rule
increases the total renewable fuel volume by 6 percent from 2016 to 2017. While these volume mandates are generally lower than
the statutory mandates, they represent a slight increase over the volumes initially proposed by the EPA for this three-year period
and such volume mandates could be increased in the future. There continues to be a shortage of advanced biofuel production
resulting in increased difficulties meeting RFS2 mandates. It is possible we could find ourselves unable to blend sufficient quantities
of ethanol and biodiesel to meet our requirements and would, therefore, have to purchase an increasing number of RINs. It is not
possible at this time to predict with certainty what those volumes or costs may be, but given the potential increase in volumes and
the volatile price of RINs, increases in renewable volume requirements could have an adverse impact on our results of operations.
Finally, while there is no current regulatory standard that authenticates RINs that may be purchased on the open market from third
parties, we believe that the RINs we purchase are from reputable sources, are valid and serve to demonstrate compliance with
applicable RFS2 requirements. However, if any of the RINs purchased by us on the open market are subsequently found by EPA
to be invalid, we could secure significant costs, penalties, or other liabilities in connection with replacing any invalid RINs.
Additional changes in fuel standards with respect to sulfur content of gasoline, called Tier 3 standards, to reduce vehicle emissions
were finalized in 2014. These new requirements, other requirements of the CAA, and other presently existing or future
environmental regulations may cause us to make substantial capital expenditures and purchase credits at significant cost to enable
our refineries to produce products that meet applicable requirements.
Climate Change - In recent years, various legislative and regulatory measures to address climate change and greenhouse gas
(“GHG”) emissions (including carbon dioxide, methane and nitrous oxides) have been discussed or implemented. They include
proposed and enacted federal regulation and state actions to develop statewide, regional or nationwide programs designed to
control and reduce GHG emissions from fixed sources, such as our refineries, as well as power plants, mobile transportation
sources and fuels. Although it is not possible to predict the requirements of any GHG legislation that may be enacted, any laws
or regulations that may be adopted to restrict or reduce GHG emissions will likely require us to incur increased operating and
capital costs. In August 2015, the EPA finalized the “Clean Power Plan” requiring states to reduce carbon dioxide emissions from
coal fired power plants that will likely result in a combination of plant closures, switching to renewable energy and natural gas,
and demand reduction. In February 2016, the U.S. Supreme Court stayed implementation of the rule pending judicial challenges
to the rule. At this time, we cannot predict the outcome of this litigation. In any event, this rule would not directly affect our
operations, but it could result in increased power costs for our refineries in future years.
EPA rules require us to report GHG emissions from our refinery operations and consumer use of fuel products produced at our
refineries on an annual basis. While the cost of compliance with the reporting rule is not material, data gathered under the rule
may be used in the future to support additional regulation of GHG. Moreover, the EPA directly regulates GHG emissions from
refineries and other major sources through the Prevention of Significant Deterioration (“PSD”) and Federal Operating Permit
programs and may require Best Available Control Technology (“BACT”) for GHG emissions above a certain threshold if emissions
of other pollutants would otherwise require PSD permitting. While this does not impose any limits or controls on GHG emissions
from current operations, GHG emission increases from future projects or operational changes, such as capacity increases, may be
impacted and required to meet emission limits or technological requirements pertaining to GHG emissions, such as BACT. Severe
limitations on GHG emissions could also adversely affect demand for the gasoline that we produce. Finally, it should be noted
that 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, floods and other climatic events; if any
such effects were to occur, they could have an adverse effect on our operations.
Water Discharges - 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. In September 2015, new EPA and U.S. Army Corps of Engineers (“Corps”) rules defining the
scope of the EPA’s and the Corps’ jurisdiction became effective. To the extent the rule expands the scope of the CWA’s jurisdiction,
we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule
has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the
rule has been stayed pending resolution of the court challenge. Also, pursuant to the CWA and its implementing regulations, we
may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to
develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with
storage of significant quantities of oil.
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Hazardous Substances and Wastes - We generate wastes that may be subject to the Resource Conservation and Recovery Act 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. The EPA is currently working on several rulemakings that could impact how our
refineries manage various waste streams. While these rulemakings are still in development, it does not appear that these rules will
significantly impact our refineries.
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 strict 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.
Oil Pollution Act - The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose a variety of requirements on
“responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States
waters. A “responsible party” includes the owner or operator of an onshore facility. OPA assigns liability to each responsible party
for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot
take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a
federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability
limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible
party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup
and restoration costs that could be incurred in connection with an oil spill.
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 that 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, 2016, we had an accrual of $96.4 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.
Occupational Health and Safety - Our operations are also subject to various laws and regulations relating to occupational health
and safety. We maintain a myriad of safety programs, safety-related maintenance programs, implement a regiment of training
requirements and otherwise comply with a host of occupational safety and health standards and regulations as part of our ongoing
efforts to ensure compliance with all applicable laws and regulations in this area. As part of our compliance efforts, we have
established hazard communications programs pursuant to the Occupational Safety and Health Administration’s (“OSHA”) hazard
communication standard, and state right-to-know standards where applicable, which require the communication of information
regarding chemical hazards in the workplace associated with chemicals manufactured or handled in our facilities. EPA regulations
under Title III of the Federal Superfund Amendment and Reauthorization Act and related federal or comparable state statutes also
require that information be maintained concerning hazardous materials used in or released from our operations and that this
information be provided to state and local government authorities and citizens under certain circumstances. Our operations are
also subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the
consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. The EPA has imposed substantially
similar requirements under its Risk Management Plan (“RMP”) regulations. In January 2017, the EPA finalized revisions to the
RMP, significantly expanding its requirements with respect to enhanced requirements for incident investigation and accident
history reporting, emergency preparedness, and the performance process hazard analyses and third party compliance audits.
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Although, to date, OSHA has not proposed any revisions expanding or imposing new PSM requirements, in January 2017, OSHA
announced changes to its National Emphasis Program and specifically identified oil refineries as facilities for increased inspections.
The changes also instruct inspectors to use data gathered from EPA RMP inspections to identify refiners for additional PSM
inspections. Compliance with applicable state and federal occupational health and safety laws and regulations, as well as
environmental regulations, has required, and continues to require, substantial expenditures.
Occupational health and environmental legislation, regulations and regulatory programs change frequently. We cannot predict
what additional occupational 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 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.
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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 headings provided in this Item 1A. are for convenience and reference purposes only and shall not affect or limit the extent or
interpretation of the risk factors.
The availability and cost of renewable identification numbers and other required credits could have an adverse effect on our
financial condition and results of operations.
Pursuant to the 2007 Energy Independence and Security Act, the EPA promulgated the RFS2 regulations reflecting the increased
volume of renewable fuels mandated to be blended into the nation's fuel supply. The regulations, in part, require refiners to add
annually increasing amounts of “renewable fuels” to their petroleum products or purchase credits, known as RINs, in lieu of such
blending. We currently purchase RINs for some fuel categories on the open market in order to comply with the quantity of renewable
fuels we are required to blend under the RFS2 regulations. Recently, due in part to the nation's fuel supply approaching the “blend
wall” (the 10% ethanol limit prescribed by most automobile warranties), the price of RINs has been extremely volatile with the
price dramatically increasing in recognition of the decrease in RINs availability. While we cannot predict the future prices of RINs,
the costs to obtain the necessary number of RINs could be material. If we are unable to pass the costs of compliance with the RFS2
regulations on to our customers, if sufficient RINs are unavailable for purchase, if we have to pay a significantly higher price for
RINs or if we are otherwise unable to meet the RFS2 mandates, our financial condition and results of operations could be adversely
affected.
In addition, the RFS2 regulations are highly complex and evolving, requiring us to periodically update our compliance systems. The
RFS2 regulations require the EPA to determine and publish the applicable annual volume and percentage standards for each
compliance year by November 30 for the forthcoming year, and such blending percentages could be higher or lower than amounts
estimated and accrued for in our consolidated financial statements. The future cost of RINs is difficult to estimate until such time
as the EPA finalizes the applicable standards for the forthcoming compliance year. Moreover, in addition to increased price volatility
in the RIN market, there have been multiple instances of RINs fraud occurring in the marketplace over the past several years. The
EPA has initiated several enforcement actions against refiners who purchase fraudulent RINs, resulting in substantial costs to the
refiner. We cannot predict with certainty our exposure to increased RINs costs in the future, nor can we predict the extent by which
costs associated with RFS2 regulations will impact our future results of operations.
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, crude
oil differentials (including regional and grade differentials), 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.
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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. Also, in
December 2015, the U.S. Congress lifted the ban on the ability of producers to export domestic crude oil. This could potentially
impact crack spreads and price differentials between domestic and foreign crude oils. A deterioration of crack spreads or price
differentials between domestic and foreign crude oils could have a material adverse effect on our business, financial condition,
results of operations and cash flows.
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 and can vary year to year in the event of
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. 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. Also, our crude oil and refined products inventories are valued at the lower of cost or market under the last-
in, first-out (“LIFO”) inventory valuation methodology. If the market value of our inventory were to decline to an amount less
than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of products sold even when there
is no underlying economic impact at that point in time. For example, we recorded a non-cash decrease to cost of products sold in
the amount of $291.9 million and an increase of $227.0 million for the years ended December 31, 2016 and 2015, respectively.
Continued volatility in crude oil and refined products prices could result in additional lower of cost or market inventory charges
in the future, or in reversals reducing cost of products sold in subsequent periods should prices recover.
A material decrease in the supply of crude oil or other raw materials available to our refineries could significantly reduce our
production levels and negatively affect our operations.
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.
For certain raw materials and utilities used by our refineries, there are a limited number of suppliers and, in some cases, the supplies
are specific to the particular geographic region in which a facility is located. It is also common in the refining industry for a facility
to have a sole, dedicated source for its utilities, such as steam, electricity, water and gas. Having a sole or limited number of
suppliers may limit our negotiating power, particularly in the case of rising raw material costs. Any new supply agreements we
enter into may not have terms as favorable as those contained in our current supply agreements.
Additionally, there is growing concern over the reliability of water sources. The decreased availability or less favorable pricing
for water as a result of population growth, drought or regulation could negatively impact our operations.
If our raw material, utility or water supplies were disrupted, our businesses may incur increased costs to procure alternative supplies
or incur excessive downtime, which would have a direct negative impact on our operations.
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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 obtaining or renewing permits, licenses, registrations and
other authorizations;
societal and political pressures and other forms of opposition;
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;
•
• market-related increases in a project's debt or equity financing costs; and/or
•
nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with
a project.
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 or businesses 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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•
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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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The anticipated benefits of our PCLI acquisition may not be realized fully or at all or may take longer to realize than expected.
The PCLI acquisition will require management to devote significant attention and resources to integrating the PCLI business with
our business, and involves the operation of businesses in other countries. Delays in this process could adversely affect our business,
financial results, financial condition and stock price. Even if we are able to integrate our business operations successfully, there
can be no assurance that this integration will result in the realization of the full benefits of synergies, cost savings, innovation and
operational efficiencies that we currently expect from this integration or that these benefits will be achieved within the anticipated
time frame.
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.
Our refinery and pipeline operations are subject to federal, state and local laws regulating, among other things, the generation,
storage, handling, use, transportation and distribution of petroleum and hazardous substances by pipeline, truck, rail and barge,
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. In addition, as a result of our recent
acquisition of PCLI and its subsidiaries, we have manufacturing and distribution operations in Canada that are subject to Canadian
national and provincial environmental laws and regulations and similar laws in other foreign countries. Permits or other
authorizations are required under these laws for the operation of our refineries, pipelines and related operations, and these permits
and authorizations 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. For
example, in October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion for both the 8-hour primary and
secondary standards. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit
our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could
be significant. Also, in February 2016, a new EPA rule became effective that amends three refinery standards already in effect,
imposing additional or, in some cases, new emission control requirements on subject refineries. The final rule requires, among
other things, benzene monitoring at the refinery fence line and submittal of fence line monitoring data to the EPA on a quarterly
basis; upgraded storage tank controls requirements, including new applicability thresholds; enhanced performance requirements
for flares, continuous monitoring of flares and pressure release devices and analysis and remedy of flare release events; and
compliance with emissions standards for delayed coking units. Refineries have up to three years from the effective date of the
final rule to come into compliance with certain requirements of the rule, such as the performance requirements for flares, while
other aspects of the rule require compliance to be achieved at a sooner date. In July 2016, the EPA issued a finale rule providing
refiners an additional 18 months to comply with a small subset of the rules related to air emissions resulting from startup, shutdown
and maintenance events. More recently, in December 2016, the EPA granted petitions for reconsideration from industry and
environmental organizations on aspects of the rule related to work practice standards for certain process units and equipment, as
well as fence line monitoring requirements. To date, EPA has not published revised rules. These new rules, as well as subsequent
rulemaking under the CAA or similar laws, or new agency interpretations of existing laws and regulations, may necessitate
additional expenditures in future years and result in increased costs on our operations. Compliance with applicable environmental
laws, regulations and permits will continue to have an impact on our operations, results of our 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, but are not limited to, soil, groundwater and waterway 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 local, state, provincial, 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 our
employees, communities, stakeholders, reputation and results of operations.
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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 or the Government of Canada. 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. In Canada, fuel content legislation also exists at the federal and provincial level. 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 or regulations could result in increased operating costs and reduced demand for
the refined products we produce.
The EPA has determined that emissions of carbon dioxide, methane and other greenhouse gas emissions, or “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. For example, the EPA
adopted rules that require certain large stationary sources to obtain permits to authorize emissions of GHGs. 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. Both the EPA and Environment and Climate Change Canada have adopted regulations
that limit GHG emissions from automobiles and light-duty trucks, which may result in a reduction in demand for the refined
products that we produce.
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 established 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.
In Canada, the federal and provincial governments have also considered, and in some cases adopted, legislation to reduce GHG
emissions. To date, two provinces (Quebec and Ontario) have also adopted cap and trade programs.
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.
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.
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Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions for which we may not be
adequately insured.
Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions such as natural disasters, adverse
weather, accidents, maritime disasters (including those involving marine vessels/terminals), fires, explosions, hazardous
materials releases, cyber-attacks, power failures, mechanical failures and other events beyond our control. These events could
result in an injury, loss of life, property damage or destruction, as well as a curtailment or an interruption in our operations and
may affect our ability to meet marketing commitments.
We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates and exclusions from
coverage may limit our ability to recover the amount of the full loss in all situations. As a result of market conditions, premiums
and deductibles for certain of our insurance policies could increase. In some instances, certain insurance could become unavailable
or available only for reduced amounts of coverage. We are not fully insured against all risks incident to our business and therefore,
we self-insure certain risks. 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.
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. If a significant accident or event occurs that is self-
insured or not fully insured, it could have a material adverse effect on our business, financial condition and results of operations.
An impairment of our long-lived assets or goodwill could reduce our earnings or negatively impact our financial condition
and results of operations.
An impairment of our long-lived assets or goodwill could reduce our earnings or negatively impact our results of operations and
financial condition. We continually monitor our business, the business environment and the performance of our operations to
determine if an event has occurred that indicates that a long-lived asset or goodwill may be impaired. If a triggering event occurs,
which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover
the carrying value based on the ability to generate future cash flows. We may also conduct impairment testing based on both the
guideline public company and guideline transaction methods. Our long-lived assets and goodwill impairment analyses are sensitive
to changes in key assumptions used in our analysis, estimates of future crack spreads, forecasted production levels, operating costs
and capital expenditures. If the assumptions used in our analysis are not realized, it is possible a material impairment charge may
need to be recorded in the future. We cannot accurately predict the amount and timing of any additional impairments of long-lived
assets or goodwill in the future.
As market prices for refined products and market prices for crude oil continue to fluctuate, we will need to continue to evaluate
the carrying value of our refinery reporting units. During the year ended December 31, 2016, we recorded goodwill and long-
lived asset impairment charges of $309.3 million and $344.8 million, respectively, on the carrying value of our Cheyenne Refinery.
Additionally, the fair value of our El Dorado reporting unit currently exceeds its carrying value by approximately 20%. A reasonable
expectation exists that future deterioration in gross margins could result in an impairment of goodwill and the long-lived assets
of the El Dorado reporting unit at some point in the future. Any additional impairment charges that we may take in the future could
be material to our results of operations and financial condition.
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.
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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.
Also, the potential operation of new or expanded refined product transportation pipelines, or the conversion of existing pipelines
into refined product transportation pipelines, could impact the supply of refined products to our existing markets and negatively
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.
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 the Cheyenne, El Dorado, Navajo, Woods Cross, and Tulsa Refineries 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.
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.
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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. Recently, the equity and debt markets for many energy
industry companies have been adversely affected by low oil prices. 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 any existing revolving credit facility and
other debt instruments may be unwilling or unable to meet their funding obligations, or we may experience a decrease in our
capacity to issue debt or obtain commercial credit or a deterioration in our credit profile, including a rating agency lowering or
withdrawing of our credit ratings if, in its judgment, the circumstances warrant. 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 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 37% 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, Nevada, New Mexico,
Oklahoma, Texas, Utah, Washington and Wyoming and refinery units in Kansas and Utah. HEP generates revenues by charging
tariffs for transporting petroleum products and crude oil through its pipelines, leasing certain pipeline capacity to Alon, charging
fees for terminalling refined products and other hydrocarbons and storing and providing other services at its terminals. HEP serves
the Cheyenne, El Dorado, Navajo, Woods Cross and Tulsa Refineries under several long-term pipeline and terminal, tankage and
throughput agreements expiring in 2019 through 2026, serves the El Dorado Refinery under long-term tolling agreements expiring
in 2030 and serves the Woods Cross Refinery under long-term tolling agreements expiring in 2031. 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:
•
•
•
•
•
•
•
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, 2016.
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.
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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 (including cyber-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 (including cyber-attacks) on the energy transportation industry in general, and on us in particular, are unknown. Increased
security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to
our business. Uncertainty surrounding continued global hostilities or other sustained military campaigns, and the possibility that
infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror, may affect our operations in unpredictable
ways, including disruptions of crude oil supplies and markets for refined products. 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.
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.
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.
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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.
We may be unable to pay future 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 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 or amounts
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.
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.
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Our credit facility contains certain covenants and restrictions that may constrain our business and financing activities.
The operating and financial restrictions and covenants in our credit facility 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) limitations on
liens and indebtedness; (ii) a prohibition on changes in control and (iii) restrictions on engaging in mergers and consolidations. If
we fail to satisfy the covenants set forth in the credit facility or another event of default occurs under the credit 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. If we desire to undertake
a transaction that is prohibited by the covenants in our credit facility, we will need to obtain consent under our credit facility. Such
refinancing may not be possible or may not be available on commercially acceptable terms.
Our business may suffer due to a departure of any of our key senior executives or other key employees. 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, 2016, 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.
The market price of our common stock may fluctuate significantly, and the value of a stockholder’s investment could be
impacted.
The market price of our common stock may be influenced by many factors, some of which are beyond our control, including:
•
•
•
•
•
•
•
•
our quarterly or annual earnings or those of other companies in our industry;
changes in accounting standards, policies, guidance, interpretations or principles;
general economic, industry and stock market conditions;
the failure of securities analysts to cover our common stock or changes in financial estimates by analysts;
future sales of our common stock;
announcements by us or our competitors of significant contracts or acquisitions;
sales of common stock by us, our senior officers or our affiliates; and/or
the other factors described in these Risk Factors.
In recent years, the stock market has experienced extreme price and volume fluctuations. This volatility has had a significant
impact on the market price of securities issued by many companies, including companies in our industry. The price of our common
stock could fluctuate based upon factors that have little or nothing to do with our company, and these fluctuations could materially
reduce our stock price.
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, based on advice of counsel, management believes that
the resolution of these proceedings through settlement or adverse judgment will not either individually or in the aggregate have
a materially adverse effect on our financial condition, results of operations or cash flows.
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 financial condition, results of operations or cash flows.
Cheyenne
HollyFrontier Cheyenne Refining LLC (“HFCR”), our wholly-owned subsidiary, completed certain environmental audits at the
Cheyenne Refinery regarding compliance with federal and state environmental requirements. By letters dated October 5, 2012,
November 7, 2012, and January 10, 2013, and pursuant to the EPA's audit policy to the extent applicable, HFCR submitted reports
to the EPA voluntarily disclosing non-compliance with certain emission limitations, reporting requirements, and provisions of a
2009 federal consent decree. By letters dated October 31, 2012; February 6, 2013; June 21, 2013; July 9, 2013 and July 25, 2013,
and pursuant to applicable Wyoming audit statutes, HFCR submitted environmental audit reports 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 permit and other environmental regulatory requirements. No further action has been taken by either agency
at this time.
El Dorado
The El Dorado Refinery has been engaged in discussions with the EPA regarding potential Clean Air Act violations relating to
flaring devices at the refinery as well as other equipment. The El Dorado Refinery has responded to two separate information
requests covering air emissions for a time frame from January 1, 2009 through May 31, 2014. The EPA also conducted an on-site
Clean Air Act - Sec. 112r Risk Management Program (“RMP”) compliance audit at the El Dorado Refinery and notified the El
Dorado Refinery of 20 alleged “deficiencies” related to that inspection. Although no Notice or Finding of Violation has been issued
by the EPA in connection with either the Clean Air Act inquiry or the 112r inspection, the EPA and the U.S. Department of Justice
have indicated that the federal government believes it has claims for civil penalties relating to the information provided in response
to the information requests and the RMP inspection. We have had a preliminary discussion with the government parties, are
continuing to evaluate the relevant law and facts and will continue to work with the EPA regarding these matters.
Tulsa
HollyFrontier Tulsa Refining LLC (“HFTR”) manufactures paraffin and hydrocarbon waxes at its Tulsa West facility. On March
11, 2014, the EPA issued a notice to HFTR of possible violations of certain provisions of the federal Toxic Substances Control
Act in connection with the manufacture of certain of these products. HFTR and the EPA met and are working productively towards
a settlement of this matter.
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.
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
2016
Fourth quarter
Third quarter
Second quarter
First quarter
2015
Fourth quarter
Third quarter
Second quarter
First quarter
$
$
$
$
$
$
$
$
34.13
27.98
37.98
41.29
52.30
54.73
43.71
45.05
$
$
$
$
$
$
$
$
22.63
22.07
22.53
29.00
39.00
42.68
35.89
30.15
$
$
$
$
$
$
$
$
0.33
0.33
0.33
0.33
0.33
0.33
0.33
0.32
227,228,500
263,014,600
201,750,800
197,404,600
153,988,900
213,026,200
157,763,200
210,069,400
In May 2015, our Board of Directors approved a $1 billion share repurchase program authorizing us to repurchase common stock
in the open market or through privately negotiated transactions based on market conditions, securities law limitations and other
relevant considerations. The following table includes repurchases made under this program during the fourth quarter of 2016.
Period
October 2016
November 2016
December 2016
Total for October to December 2016
Total Number of
Shares Purchased
Average Price
Paid Per Share
—
—
—
— $
— $
— $
—
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
— $
— $
— $
—
178,811,213
178,811,213
178,811,213
As of February 13, 2017, we had approximately 98,039 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.
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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.
2016
Years Ended December 31,
2014
2013
2015
2012
FINANCIAL DATA
For the period
Sales and other revenues
Income (loss) before income taxes (1,2)
Income tax provision
Net income (loss)
Less net income attributable to noncontrolling interest
Net income (loss) attributable to HollyFrontier
stockholders
Earnings (loss) per share attributable to HollyFrontier
stockholders - basic
Earnings (loss) per share attributable to HollyFrontier
stockholders - diluted
Cash dividends declared per common share
Average number of common shares outstanding:
Basic
Diluted
Net cash provided by operating activities
Net cash 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
Total debt (3)
Total equity
(In thousands, except per share data)
$ 10,535,700
(171,534)
19,411
(190,945)
69,508
$ 13,237,920
1,208,568
406,060
802,508
62,407
$ 19,764,327
467,500
141,172
326,328
45,036
$ 20,160,560
1,159,399
391,576
767,823
31,981
$ 20,090,724
2,787,995
1,027,962
1,760,033
32,861
$
$
$
$
$
$
$
(260,453) $
740,101
(1.48) $
(1.48) $
$
1.32
3.91
3.90
1.31
$
$
$
$
281,292
1.42
1.42
3.26
$
$
$
$
735,842
$ 1,727,172
3.66
3.64
3.20
$
$
$
8.41
8.38
3.10
176,101
176,101
188,731
188,940
197,243
197,428
200,419
201,234
204,379
205,274
$
602,271
(801,597) $
843,372
$
979,626
(381,748) $
$ (1,099,330) $
869,174
$
758,596
(292,322) $
(526,735) $
(838,392) $ (1,160,035) $
$ 1,662,687
(711,104)
(772,788)
$ 1,134,727
$ 1,767,780
$ 9,435,661
$ 2,235,137
$ 5,301,985
210,552
$
$
587,450
$ 8,388,299
$ 1,040,040
$ 5,809,773
$ 1,042,095
$ 1,549,004
$ 9,230,047
$ 1,054,297
$ 6,100,719
$ 1,665,263
$ 2,445,953
$ 10,055,763
996,543
$
$ 6,609,398
$ 2,393,401
$ 2,961,037
$ 10,326,628
$ 1,333,869
$ 6,642,658
(1) Reflects non-cash lower of cost or market inventory valuation adjustments that increased pre-tax earnings by $291.9 million for the
year ended December 31, 2016 and decreased pre-tax earnings by $227.0 million and $397.5 million for the years ended December
31, 2015 and 2014, respectively.
(2) Includes goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million, respectively, that relate to our
Cheyenne Refinery, for the year ended December 31, 2016.
(3) Includes total HEP debt of $1,243.9 million, $1,008.8 million, $867.0 million, $806.7 million and $863.5 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.
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 nameplate
crude oil processing capacity of 457,000 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, Artesia, New Mexico, which
operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico
(collectively, the Navajo Refinery), Cheyenne, Wyoming (the Cheyenne Refinery) and Woods Cross, Utah (the Woods Cross
Refinery).
On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc. (“Purchaser”), entered into a share purchase agreement
with Suncor Energy Inc. (“Suncor”) to acquire 100% of the outstanding capital stock of Petro-Canada Lubricants Inc. (“PCLI”)
that closed on February 1, 2017. Cash consideration paid was CAD $1.125 billion, including working capital with an estimated
value of CAD $342 million. The PCLI plant, located in Mississauga, Ontario, is the largest producer of base oils in Canada with
15,600 BPD of lubricant production capacity, and is the only North American producer of high margin Group III base oils.
For the year ended December 31, 2016, net loss attributable to HollyFrontier stockholders was $260.5 million compared to net
income of $740.1 million and $281.3 million for the years ended December 31, 2015, and 2014, respectively. Overall gross refining
margins per produced product sold for 2016 decreased 48% over the year ended December 31, 2015, which was due principally
to lower crack spreads throughout 2016. Included in our financial results for the current year were non-cash items consisting of
goodwill and long-lived asset impairment charges, offset by an inventory reserve adjustment.
Pursuant to the 2007 Energy Independence and Security Act, the EPA promulgated the RFS2 regulations, which increased the
volume of renewable fuels mandated to be blended into the nation's fuel supply. The regulations, in part, require refiners to add
annually increasing amounts of “renewable fuels” to their petroleum products or purchase credits, known as RINs, in lieu of such
blending. Compliance with RFS2 regulations significantly increases our cost of products sold, with RINs costs totaling $242.0
million for the year ended December 31, 2016. Year-over-year increased costs of ethanol blended into our petroleum products,
which exceeded the cost of crude oil, also contributed to lower refining margins for the year.
OUTLOOK
Our profitability is affected by the spread, or differential, between the market prices for crude oil on the world market (which is
based on the price for Brent, North Sea Crude) and the price for inland U.S. crude oil (which is based on the price for WTI). We
expect continued volatility in the pricing relationship between inland and coastal crude, currently averaging in the range of $1.00
to $2.00 per barrel.
We have recently curtailed production at the Woods Cross refinery due to insufficient crude supply provided by the Plains Rocky
Mountain Pipeline. We are unable to predict the duration of the supply disruption at this time, but are considering alternative
solutions and working with Plains and others to rectify the situation.
Our RINs costs are material and represent a cost of products sold. The price of RINs may be extremely volatile due to real or
perceived future shortages in RINs. As of December 31, 2016, we are purchasing RINs in order to meet approximately half of our
renewable fuel requirements.
A more detailed discussion of our financial and operating results for the years ended December 31, 2016, 2015 and 2014 is presented
in the following sections.
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Results Of Operations
Financial Data
2016
Years Ended December 31,
2015
(In thousands, except per share data)
2014
Sales and other revenues
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization):
Cost of products sold (exclusive of lower of cost or market inventory
valuation adjustment)
Lower of cost or market inventory valuation adjustment
Operating expenses (exclusive of depreciation and amortization)
General and administrative expenses (exclusive of depreciation and
amortization)
Depreciation and amortization
Goodwill and asset impairment
Total operating costs and expenses
Income (loss) from operations
Other income (expense):
Earnings (loss) of equity method investments
Interest income
Interest expense
Loss on early extinguishment of debt
Other, net
Income (loss) before income taxes
Income tax provision
Net income (loss)
Less net income attributable to noncontrolling interest
Net income (loss) attributable to HollyFrontier stockholders
Earnings (loss) per share attributable to HollyFrontier stockholders:
Basic
Diluted
Cash dividends declared per common share
Average number of common shares outstanding:
Basic
Diluted
Other Financial Data
Net cash provided by operating activities
Net cash used for investing activities
Net cash provided by (used for) financing activities
Capital expenditures
EBITDA (1)
Adjusted EBITDA (2)
$
10,535,700
$
13,237,920
$
19,764,327
8,765,927
(291,938)
8,473,989
1,018,839
125,648
363,027
654,084
10,635,587
(99,887)
14,213
2,491
(72,192)
(8,718)
(7,441)
(71,647)
(171,534)
19,411
(190,945)
69,508
(260,453) $
(1.48) $
(1.48) $
$
1.32
176,101
176,101
10,239,218
226,979
10,466,197
1,060,373
120,846
346,151
—
11,993,567
1,244,353
(3,738)
3,391
(43,470)
(1,370)
9,402
(35,785)
1,208,568
406,060
802,508
62,407
740,101
3.91
3.90
1.31
188,731
188,940
$
$
$
$
17,228,385
397,478
17,625,863
1,144,940
114,609
363,381
—
19,248,793
515,534
(2,007)
4,430
(43,646)
(7,677)
866
(48,034)
467,500
141,172
326,328
45,036
281,292
1.42
1.42
3.26
197,243
197,428
2016
Years Ended December 31,
2015
(In thousands)
2014
602,271
$
(801,597) $
$
843,372
$
479,790
$
200,404
$
575,956
979,626
$
(381,748) $
(1,099,330) $
$
676,155
$
1,533,761
$
1,760,740
758,596
(292,322)
(838,392)
564,821
832,738
1,230,216
$
$
$
$
$
$
$
$
$
$
(1) Earnings before interest, taxes, depreciation and amortization, which we refer to as “EBITDA,” is calculated as net income
(loss) plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization.
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(2) "Adjusted EBITDA" is calculated as EBITDA plus or minus (i) lower of cost or market inventory valuation adjustment and
(ii) goodwill and asset impairment charges. EBITDA and Adjusted EBITDA are not calculations provided for under GAAP;
however, the amounts included in these calculations are derived from amounts included in our consolidated financial
statements. EBITDA and Adjusted EBITDA should not be considered as alternatives 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
and Adjusted EBITDA are not necessarily comparable to similarly titled measures of other companies. They are presented
here because they are widely used financial indicators used by investors and analysts to measure performance. EBITDA and
Adjusted EBITDA are also used by our management for internal analysis and as a basis for financial covenants. EBITDA
and Adjusted EBITDA presented above are 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 20 “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 non-cash effects of goodwill and asset impairments charges, lower
of cost or market inventory valuation adjustments and 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 (8)
Refinery operating expenses (9)
Net operating margin (8)
Refinery operating expenses per throughput barrel (10)
Years Ended December 31,
2016
2015
2014
423,910
457,480
442,110
435,420
464,980
432,560
463,580
446,560
438,000
488,350
406,180
436,400
425,010
420,990
461,640
92.8%
97.6%
91.7%
$
$
$
58.02
49.64
8.38
5.57
2.81
5.30
$
$
$
71.32
55.25
16.07
5.71
10.36
5.39
$
$
$
110.19
96.21
13.98
6.38
7.60
6.16
(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, 2016, our consolidated crude capacity
increased from 443,000 BPSD to 457,000 BPSD upon completion of our Woods Cross Refinery expansion project.
(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) Excludes lower of cost or market inventory valuation adjustments of that increased refinery gross margin by $291.9
million for the year ended December 31, 2016 and decreased refinery gross margin by $227.0 million and $397.5 million
for the years ended December 31, 2015 and 2014, respectively.
(9) Represents operating expenses of our refineries, exclusive of depreciation and amortization.
(10) Represents refinery operating expenses, exclusive of depreciation and amortization, divided by refinery throughput.
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Results of Operations – Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Summary
Net loss attributable to HollyFrontier stockholders for the year ended December 31, 2016 was $260.5 million ($1.48 per basic and
diluted share), a $1,000.6 million decrease compared to net income attributable to HollyFrontier stockholders of $740.1 million
($3.91 per basic and $3.90 per diluted share) for the year ended December 31, 2015. Net income decreased due principally to non-
cash goodwill and long-lived asset impairment charges of $309.3 million and $344.8 million, respectively, and a year-over-year
decrease in refining margins and sales volumes, net of the effects of a year-over-year change in lower of cost or market inventory
reserve adjustments. For the year ended December 31, 2016, lower of cost or market inventory reserve adjustments increased pre-
tax earnings by $291.9 million compared to a pre-tax earnings decrease of $227.0 million for the year ended December 31, 2015.
Collectively, the impairment charges, net of the lower of cost or market valuation benefit, reduced 2016 pre-tax income by $362.1
million. Refinery gross margins for the year ended December 31, 2016 decreased to $8.38 per produced barrel from $16.07 for
the year ended December 31, 2015.
Sales and Other Revenues
Sales and other revenues decreased 20% from $13,237.9 million for the year ended December 31, 2015 to $10,535.7 million for
the year ended December 31, 2016 due to a year-over-year decrease in sales prices and lower refined product sales volumes. The
average sales price we received per produced barrel sold decreased 19% from $71.32 for the year ended December 31, 2015 to
$58.02 for the year ended December 31, 2016. Sales and other revenues for the years ended December 31, 2016 and 2015 include
$68.9 million and $66.7 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to
unaffiliated parties.
Cost of Products Sold
Total cost of products sold decreased 19% from $10,466.2 million for the year ended December 31, 2015 to $8,474.0 million for
the year ended December 31, 2016, due principally to lower crude oil costs and lower sales volumes of refined products.
Additionally, this decrease reflects a $291.9 million benefit that is attributable to a reduction in the lower of cost or market reserve
for the year ended December 31, 2016, a $518.9 million increase compared to a charge of $227.0 million for the same period of
last year. The reserve at December 31, 2016 is based on market conditions and prices at that time. Excluding this non-cash
adjustment, 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 10% from $55.25 for the year ended December 31, 2015 to $49.64 for the year ended
December 31, 2016.
Gross Refinery Margins
Gross refinery margin per produced barrel decreased 48% from $16.07 for the year ended December 31, 2015 to $8.38 for the
year ended December 31, 2016. This was due to the effects of a decrease in the average per barrel sales price for refined products
sold, partially offset by decreased crude oil and feedstock prices during the current year. Gross refinery margin does not include
the non-cash effects of lower of cost or market inventory valuation adjustments goodwill and asset impairment charges or
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, decreased 4% from $1,060.4 million for the year ended
December 31, 2015 to $1,018.8 million for the year ended December 31, 2016 due principally to lower natural gas fuel and
maintenance costs compared to 2015. For the years ended December 31, 2016 and 2015, operating expenses include $90.4 million
and $102.3 million, respectively, in costs attributable to HEP operations.
General and Administrative Expenses
General and administrative expenses increased 4% from $120.8 million for the year ended December 31, 2015 to $125.6 million
for the year ended December 31, 2016, due principally to PCLI acquisition costs. For the years ended December 31, 2016 and
2015, general and administrative expenses include $10.1 million and $10.2 million, respectively, in costs attributable to HEP
operations.
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Depreciation and Amortization Expenses
Depreciation and amortization increased 5% from $346.2 million for the year ended December 31, 2015 to $363.0 million for the
year ended December 31, 2016. This increase was due principally to depreciation and amortization attributable to capitalized
improvement projects and capitalized refinery turnaround costs. For the years ended December 31, 2016 and 2015, depreciation
and amortization expenses include $68.8 million and $61.7 million, respectively, in costs attributable to HEP operations.
Goodwill and Asset Impairment
During the year ended December 31, 2016, we recorded goodwill and long-lived asset impairment charges of $309.3 million and
$344.8 million, respectively, that relate to our Cheyenne Refinery. See Note 10 “Goodwill” in the Notes to Consolidated Financial
Statements for additional information on the Cheyenne impairment.
Interest Income
Interest income for the year ended December 31, 2016 was $2.5 million compared to $3.4 million for the year ended December 31,
2015. This decrease was due to lower investment levels in marketable debt securities during 2015.
Interest Expense
Interest expense was $72.2 million for the year ended December 31, 2016 compared to $43.5 million for the year ended
December 31, 2015. This increase was due to interest attributable to higher debt levels during the current year relative to 2015.
For the years ended December 31, 2016 and 2015, interest expense included $52.6 million and $36.9 million, respectively, in
interest costs attributable to HEP operations.
Loss on Early Extinguishment of Debt
In March 2016, we recognized an $8.7 million loss on the early retirement of a financing obligation, a component of outstanding
debt, upon HEP's purchase of crude oil tanks from an affiliate of Plains. See Note 12 "Debt" in the Notes to Consolidated Financial
Statements for additional information on this financing obligation.
In June 2015, we recognized a $1.4 million early extinguishment loss on the redemption of our $150.0 million aggregate principal
amount of 6.875% senior notes maturing November 2018.
Income Taxes
For the year ended December 31, 2016, we recorded income tax expense of $19.4 million compared to $406.1 million for the year
ended December 31, 2015. This decrease was due principally to a pre-tax loss during the year ended December 31, 2016 compared
to pre-tax earnings during the year ended 2015. Our effective tax rates, before consideration of earnings attributable to the
noncontrolling interest, were (11.3)% and 33.6% for the years ended December 31, 2016 and 2015, respectively. Our current year
effective tax rate reflects the effects of the $309.3 million goodwill impairment charge, a significant driver of our $171.5 million
loss before income taxes for the year ended December 31, 2016, that is not deductible for income tax purposes.
Results of Operations – Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Summary
Net income attributable to HollyFrontier stockholders for the year ended December 31, 2015 was $740.1 million ($3.91 per basic
and $3.90 per diluted share), a $458.8 million increase compared to $281.3 million ($1.42 per basic and diluted share) for the year
ended December 31, 2014. Net income increased due principally to a year-over-year increase in refining margins and sales volumes,
improved operational reliability and lower operating expenses. Additionally, non-cash lower of cost or market inventory valuation
adjustments reduced 2015 pre-tax income by $227.0 million, compared to $397.5 million in 2014. Refinery gross margins for the
year ended December 31, 2015 increased to $16.07 per produced barrel from $13.98 for the year ended December 31, 2014.
Sales and Other Revenues
Sales and other revenues decreased 33% from $19,764.3 million for the year ended December 31, 2014 to $13,237.9 million for
the year ended December 31, 2015 due to a year-over-year decrease in sales prices, partially offset by higher refined product sales
volumes. The average sales price we received per produced barrel sold decreased 35% from $110.19 for the year ended December 31,
2014 to $71.32 for the year ended December 31, 2015. Sales and other revenues for the years ended December 31, 2015 and 2014
include $66.7 million and $57.3 million, respectively, in HEP revenues attributable to pipeline and transportation services provided
to unaffiliated parties.
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Cost of Products Sold
Total cost of products sold decreased 41% from $17,625.9 million for the year ended December 31, 2014 to $10,466.2 million for
the year ended December 31, 2015, due principally to lower crude oil costs, partially offset by higher sales volumes of refined
products. Additionally, cost of products sold reflects a $227.0 million charge that is attributable to the lower of cost or market
reserve for the year ended December 31, 2015, a $170.5 million decrease compared to $397.5 million for the year ended December
31, 2014. The reserve at December 31, 2015 was based on market conditions and prices at that time. Excluding this non-cash
adjustment, 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 43% from $96.21 for the year ended December 31, 2014 to $55.25 for the year ended
December 31, 2015.
Gross Refinery Margins
Gross refinery margin per produced barrel increased 15% from $13.98 for the year ended December 31, 2014 to $16.07 for the
year ended December 31, 2015. This was due to the effects of decreased crude oil and feedstock prices, partially offset by a decrease
in the average per barrel sales price for refined products sold during the current year. Gross refinery margin does not include the
non-cash effects of lower of cost or market inventory valuation adjustments or 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, decreased 7% from $1,144.9 million for the year ended
December 31, 2014 to $1,060.4 million for the year ended December 31, 2015 due principally to a year-over-year decrease in
repair and maintenance and natural gas fuel costs and lower environmental accruals compared to 2014. For the years ended
December 31, 2015 and 2014, operating expenses include $102.3 million and $104.8 million, respectively, in costs attributable to
HEP operations.
General and Administrative Expenses
General and administrative expenses increased 5% from $114.6 million for the year ended December 31, 2014 to $120.8 million
for the year ended December 31, 2015. This is attributable to overall higher incentive compensation and legal costs in 2015, net
of the effects of state high-wage credits recognized during the second quarter of 2015. For the years ended December 31, 2015
and 2014, general and administrative expenses include $10.2 million and $8.5 million, respectively, in costs attributable to HEP
operations.
Depreciation and Amortization Expenses
Depreciation and amortization decreased 5% from $363.4 million for the year ended December 31, 2014 to $346.2 million for the
year ended December 31, 2015. This decrease was due principally to the recognition of higher accelerated depreciation levels of
assets no longer in operation during 2014, partially offset by depreciation and amortization during 2015 attributable to capitalized
improvement projects and capitalized refinery turnaround costs. For the years ended December 31, 2015 and 2014, depreciation
and amortization expenses include $61.7 million and $60.9 million, respectively, in costs attributable to HEP operations.
Interest Income
Interest income for the year ended December 31, 2015 was $3.4 million compared to $4.4 million for the year ended December 31,
2014. This decrease was due to lower investment levels in marketable debt securities during 2015.
Interest Expense
Interest expense was $43.5 million for the year ended December 31, 2015 compared to $43.6 million for the year ended
December 31, 2014. This slight decrease is due principally to the effects of lower HollyFrontier interest expense as a result of the
June 2015 redemption of the $150.0 million HollyFrontier senior notes, net of increased HEP interest expense attributable to higher
year-over-year HEP debt levels. For the years ended December 31, 2015 and 2014, interest expense included $36.9 million and
$36.1 million, respectively, in interest costs attributable to HEP operations.
Loss on Early Extinguishment of Debt
In June 2015, we redeemed our $150.0 million aggregate principal amount of 6.875% senior notes maturing November 2018 at
a redemption cost of $155.2 million, at which time we recognized a $1.4 million early extinguishment loss consisting of a $5.2
million debt redemption premium, net of an unamortized premium of $3.8 million.
In March 2014, HEP redeemed its $150.0 million aggregate principal amount of 8.25% senior notes maturing March 2018 at a
redemption cost of $156.2 million, at which time it recognized a $7.7 million early extinguishment loss consisting of a $6.2 million
debt redemption premium and unamortized discount and financing costs of $1.5 million.
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Income Taxes
For the year ended December 31, 2015, we recorded income tax expense of $406.1 million compared to $141.2 million for the
year ended December 31, 2014. This increase was due principally to higher pre-tax earnings during the year ended December 31,
2015 compared to 2014. Our effective tax rates, before consideration of earnings attributable to the noncontrolling interest, were
33.6% and 30.2% for the years ended December 31, 2015 and 2014, respectively.
LIQUIDITY AND CAPITAL RESOURCES
HollyFrontier Credit Agreement
We have a $1 billion senior unsecured revolving credit facility maturing in July 2019 (the “HollyFrontier Credit Agreement”) that
was amended in February 2017, increasing the size of the credit facility to $1.35 billion and extending the maturity to February
2022. The HollyFrontier Credit Agreement may be used for revolving credit loans and letters of credit from time to time and is
available to fund general corporate purposes. During the year ended December 31, 2016, we received advances totaling $315.0
million and repaid $315.0 million under the HollyFrontier Credit Agreement. At December 31, 2016, we were in compliance with
all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $4.4 million under the HollyFrontier
Credit Agreement.
HollyFrontier Senior Notes
In March 2016 and November 2016, we issued $250 million and $750 million, respectively, in aggregate principal amount of
5.875% senior notes (the “HollyFrontier Senior Notes”) maturing April 2026. The HollyFrontier Senior Notes are unsecured and
unsubordinated obligations of ours and rank equally with all our other existing and future unsecured and unsubordinated
indebtedness.
HollyFrontier Term Loan
In April 2016, we entered into a $350 million senior unsecured term loan (the “HollyFrontier Term Loan”) maturing in April 2019.
The HollyFrontier Term Loan was fully repaid with proceeds received upon the November 2016 issuance of the HollyFrontier
Senior Notes.
HEP Credit Agreement
HEP has a $1.2 billion senior secured revolving credit facility maturing in November 2018 (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. During the year ended December 31,
2016, HEP received advances totaling $554.0 million and repaid $713.0 million under the HEP Credit Agreement. At December 31,
2016, HEP was in compliance with all of its covenants, had outstanding borrowings of $553.0 million and no outstanding letters
of credit under the HEP Credit Agreement.
HEP Senior Notes
On January 4, 2017, HEP redeemed its $300 million aggregate principal amount of 6.50% senior notes maturing March 2020 at
a redemption cost of $316.4 million, at which time HEP recognized a $12.2 million early extinguishment loss. HEP funded the
redemption with borrowings under the HEP Credit Agreement.
HEP Debt Offering
In July 2016, HEP issued $400 million in aggregate principal amount of 6.0% HEP unsecured senior notes maturing in 2024 in a
private placement. HEP used the net proceeds to repay indebtedness under the HEP Credit Agreement.
See Note 12 "Debt" in the Notes to Consolidated Financial Statements for additional information on our debt instruments.
HEP Common Unit Continuous Offering Program
On May 10, 2016, HEP established a continuous offering program under which HEP may issue and sell common units from time
to time, representing limited partner interests, up to an aggregate gross sales amount of $200 million. As of December 31, 2016,
HEP has issued 703,455 units under this program, providing $23.0 million in net proceeds. In connection with this program and
to maintain the 2% general partner interest, we made capital contributions totaling $0.5 million as of December 31, 2016.
HEP intends to use the net proceeds for general partnership purposes, which may include funding working capital, repayment of
debt, acquisitions and capital expenditures. Amounts repaid under HEP’s credit facility may be reborrowed from time to time.
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HEP Private Placement Agreement
On September 16, 2016, HEP entered into a common unit purchase agreement in which certain purchasers agreed to purchase in
a private placement 3,420,000 HEP common units, representing limited partnership interests, at a price of $30.18 per common
unit. The private placement closed on October 3, 2016, at which time HEP received proceeds of $103.0 million, which were used
to finance a portion of the Woods Cross assets acquisition. In connection with this private placement and to maintain our 2%
general partner interest in HEP, we made capital contributions totaling $2.1 million to HEP in October 2016. After this common
unit issuance, our interest in HEP is 37%, including the 2% general partner interest.
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, 2016, our cash, cash equivalents and investments in marketable securities totaled $1.1 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. These primarily consist of investments in conservative, highly-rated
instruments issued by financial institutions, government and corporate entities with strong credit standings and money market
funds.
On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a share purchase agreement with Suncor
to acquire 100% of the outstanding capital stock of PCLI that closed on February 1, 2017. Cash consideration paid was $862.1
million, or $1.125 billion in Canadian dollars.
In May 2015, our Board of Directors approved a $1 billion share repurchase program, which replaced all existing share repurchase
programs, authorizing 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 and corporate, regulatory and other relevant considerations.
This program may be discontinued at any time by our Board of Directors. As of December 31, 2016, we had remaining authorization
to repurchase up to $178.8 million under this stock repurchase program. In addition, we are authorized by our Board of Directors
to repurchase shares in an amount sufficient to offset shares issued under our compensation programs.
Cash and cash equivalents increased $644.0 million for the year ended December 31, 2016. Net cash provided by operating and
financing activities of $602.3 million and $843.4 million, respectively, exceeded net cash used for investing activities of $801.6
million. Working capital increased by $1,180.3 million during the year ended December 31, 2016.
Cash Flows – Operating Activities
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Net cash flows provided by operating activities were $602.3 million for the year ended December 31, 2016 compared to $979.6
million for the year ended December 31, 2015, a decrease of $377.4 million. Net loss for the year ended December 31, 2016 was
$190.9 million, a decrease of $993.5 million compared to net income of $802.5 million for the year ended December 31, 2015.
Non-cash adjustments to net income consisting of depreciation and amortization, goodwill and asset impairment, lower of cost or
market inventory valuation adjustment, net loss of equity method investments, inclusive of distributions, gain on sale of assets,
gain or loss on extinguishment of debt, deferred income taxes, equity-based compensation expense, fair value changes to derivative
instruments and excess tax expense from equity-based compensation totaled $846.8 million for the year ended December 31, 2016
compared to $492.0 million for the same period in 2015. Changes in working capital items increased cash flows by $74.7 million
for the year ended December 31, 2016 compared to a decrease of $195.1 million for the year ended December 31, 2015. For the
year ended December 31, 2016, turnaround expenditures increased to $125.3 million from $89.4 million for the same period of
2015.
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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Net cash flows provided by operating activities were $979.6 million for the year ended December 31, 2015 compared to $758.6
million for the year ended December 31, 2014, an increase of $221.0 million. Net income for the year ended December 31, 2015
was $802.5 million, an increase of $476.2 million compared to $326.3 million for the year ended December 31, 2014. Non-cash
adjustments to net income consisting of lower of cost or market inventory valuation adjustment, depreciation and amortization,
net loss of equity method investments, inclusive of distributions, gain on sale of assets, unamortized premium / discount on early
extinguishment of debt, deferred income taxes, equity-based compensation expense and fair value changes to derivative instruments
totaled $492.0 million for the year ended December 31, 2015 compared to $580.0 million for the same period in 2014. Changes
in working capital items decreased cash flows by $195.1 million for the year ended December 31, 2015 compared to $64.1 million
for the year ended December 31, 2014. For the year ended December 31, 2015, turnaround expenditures decreased to$89.4 million
from $96.8 million for the same period of 2014.
Cash Flows – Investing Activities and Planned Capital Expenditures
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Net cash flows used for investing activities were $801.6 million for the year ended December 31, 2016 compared to $381.7 million
for the year ended December 31, 2015, an increase of $419.8 million. Cash expenditures for properties, plants and equipment for
2016 decreased to $479.8 million from $676.2 million for the same period in 2015. These include HEP capital expenditures of
$107.6 million and $193.1 million for the years ended December 31, 2016 and 2015, respectively. In addition, in 2016, HEP
purchased a 50% interest in Cheyenne Pipeline for $42.6 million, and in 2015, a 50% interest in Frontier Pipeline for $55.0 million.
We received proceeds of $0.8 million and $19.3 million from the sale of assets during the years ended December 31, 2016 and
2015, respectively. For the years ended December 31, 2016 and 2015, we invested $546.6 million and $509.3 million, respectively,
in marketable securities and received proceeds of $266.6 million and $839.5 million, respectively, from the sale or maturity of
marketable securities.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Net cash flows used for investing activities were $381.7 million for the year ended December 31, 2015 compared to $292.3 million
for the year ended December 31, 2014, an increase of $89.4 million. Cash expenditures for properties, plants and equipment for
2015 increased to $676.2 million from $564.8 million for the same period in 2014. These include HEP capital expenditures of
$193.1 million and $198.7 million for the years ended December 31, 2015 and 2014, respectively. We received proceeds of $19.3
million and $16.6 million from the sale of assets during the years ended December 31, 2015 and 2014, respectively. For the years
ended December 31, 2015 and 2014, we invested $509.3 million and $1,025.6 million, respectively, in marketable securities and
received proceeds of $839.5 million and $1,276.4 million, respectively, from the sale or maturity of marketable securities.
Additionally, HEP purchased a 50% interest in Frontier Pipeline for $55.0 million.
Planned Capital Expenditures
HollyFrontier Corporation
Each year our Board of Directors approves our annual capital budget which includes specific projects that 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. During 2017,
we expect to spend approximately $275.0 million to $300.0 million in cash for capital projects appropriated in 2017 and prior
years. In addition, we expect to spend approximately $150.0 million to $165.0 million on refinery turnarounds. Refinery turnaround
spending is amortized over the useful life of the turnaround. Our expected capital and turnaround cash spending for 2017 is as
follows:
Type:
Sustaining
Reliability and Growth
Compliance and Safety
Turnarounds
Total
Expected Cash Spending
Range
(In millions)
75.0
100.0
90.0
135.0
400.0
$
$
85.0
115.0
100.0
150.0
450.0
$
$
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The refining industry is capital intensive and requires on-going investments to sustain our refining operations. This includes
replacement of, or rebuilding, refinery units and components that extend the useful life. We also invest in projects that improve
operational reliability and profitability via enhancements that improve refinery processing capabilities as well as production yield
and flexibility. Our capital expenditures also include projects related to environmental, health and safety compliance and include
initiatives as a result of federal and state mandates.
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, Tier 3 which mandates a reduction in the sulfur 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.
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 in
excess of a year, 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 2017 HEP capital budget is comprised of
$9.0 million for maintenance capital expenditures and $30.0 million for expansion capital expenditures. HEP expects the majority
of the expansion capital budget to be invested in refined product pipeline expansions, crude system enhancements, new storage
tanks, and enhanced blending capabilities at our racks.
Cash Flows – Financing Activities
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Net cash flows provided by financing activities were $843.4 million for the year ended December 31, 2016 compared to cash
flows used for financing activities of $1,099.3 million for the year ended December 31, 2015, an increase of $1,942.7 million.
During the year ended December 31, 2016, we received $992.6 million in net proceeds upon issuance of our 5.875% senior notes,
received $350.0 million and repaid $350.0 million under a term loan, received $315.0 million and repaid $315.0 million under
the HollyFrontier Credit Agreement, purchased $133.4 million in common stock and paid $234.0 million in dividends. In addition,
we extinguished our financing obligation with Plains for $39.5 million. Also during this period, HEP received $869.0 million and
repaid $1,028.0 million under the HEP Credit Agreement, received $394.0 million in net proceeds from issuance of HEP 6.0%
senior notes, received $125.9 million in net proceeds from the issuance of its common units and paid distributions of $92.6 million
to noncontrolling interests. During the year ended December 31, 2015, we purchased $742.8 million in common stock, paid $246.9
million in dividends and paid $155.2 million upon the redemption of our 6.875% senior notes. Also during this period, HEP
received $973.9 million and repaid $832.9 million under the HEP Credit Agreement and paid distributions of $83.3 million to
noncontrolling interests.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Net cash flows used for financing activities were $1,099.3 million for the year ended December 31, 2015 compared to $838.4
million for the year ended December 31, 2014, an increase of $260.9 million. During the year ended December 31, 2015, we
purchased $742.8 million in common stock, paid $246.9 million in dividends and paid $155.2 million upon the redemption of our
6.875% senior notes. Also during this period, HEP received $973.9 million and repaid $832.9 million under the HEP Credit
Agreement and paid distributions of $83.3 million to noncontrolling interests. During the year ended December 31, 2014, we
purchased $158.8 million in common stock, paid $647.2 million in dividends and recognized $2.0 million excess tax benefits on
our equity-based compensation. Also during this period, HEP received $642.3 million and repaid $434.3 million under the HEP
Credit Agreement, paid $156.2 million upon the redemption of HEP's 8.25% senior notes and paid distributions of $78.2 million
to noncontrolling interests.
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Contractual Obligations and Commitments
The following table presents our long-term contractual obligations as of December 31, 2016 in total and by period due beginning
in 2017. 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.
Contractual Obligations and Commitments
Total
HollyFrontier Corporation
Long-term debt - principal
Long-term debt - interest (1)
Supply agreements (2)
Transportation and storage agreements (3)
Other long-term obligations
Operating leases
Holly Energy Partners
Long-term debt - principal (4)
Long-term debt - interest (5)
Pipeline operating leases
Other agreements
Total
$
$
1,000,000
548,333
2,931,355
1,498,001
27,387
426,990
6,432,066
1,253,000
274,978
66,868
9,632
1,604,478
8,036,544
Payments Due by Period
Less than 1
Year
1-3 Years
(In thousands)
3-5 Years
Over
5 Years
$
— $
— $
58,750
462,877
136,052
11,347
68,787
737,813
117,500
786,286
258,153
11,455
116,620
1,290,014
— $ 1,000,000
254,583
1,043,729
894,033
2,500
137,601
3,332,446
117,500
638,463
209,763
2,085
103,982
1,071,793
—
59,988
6,368
4,023
70,379
808,192
553,000
101,740
12,737
4,003
671,480
$ 1,961,494
300,000
51,250
12,737
508
364,495
$ 1,436,288
400,000
62,000
35,026
1,098
498,124
$ 3,830,570
$
(1) Interest payments consist of interest on our 5.875% senior notes.
(2) 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 2017 and
2030 using current market rates. Additionally, commitments include purchases of 20,000 BPD of crude oil under a 10-year agreement
to supply our Woods Cross Refinery.
(3) 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 2017 and 2030.
(4) HEP's long-term debt consists of the $400.0 million principal balance on the 6% HEP senior notes, $300.0 million principal balance
on the 6.5% HEP senior notes and $553.0 million of outstanding borrowings under the HEP Credit Agreement. The $300 million
6.5% HEP senior notes were redeemed on January 4, 2017. The HEP Credit Agreement expires in 2018.
(5) Interest payments consist of interest on the 6% HEP senior notes, the 6.5% HEP senior notes and interest on long-term debt under
the HEP Credit Agreement. Interest on the HEP Credit Agreement debt is based on the weighted average rate of 2.98% at December 31,
2016.
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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Inventory Valuation
Inventories are stated at the lower of cost, using the LIFO method for crude oil, unfinished and finished refined products and the
average cost method for materials and supplies, or market. 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. At December 31, 2016 and 2015, market values had
fallen below historical LIFO inventory costs and, as a result, we recorded lower of cost or market inventory valuation reserves of
$332.5 million and $624.5 million, respectively.
At December 31, 2016, our lower of cost or market inventory valuation reserve was $332.5 million. This amount, or a portion
thereof, is subject to reversal as a reduction to cost of products sold in subsequent periods as inventories giving rise to the reserve
are sold, and a new reserve is established. Such a reduction to cost of products sold could be significant if inventory values return
to historical cost price levels. Additionally, further decreases in overall inventory values could result in additional charges to cost
of products sold should the lower of cost or market inventory valuation reserve be increased.
Goodwill and Long-lived Assets
As of December 31, 2016, our goodwill balance was $2.0 billion, with goodwill assigned to our refining and HEP segments of
$1.7 billion and $0.3 billion, respectively.
During the second quarter of 2016, we performed interim goodwill impairment and related long-lived asset impairment testing of
our El Dorado and Cheyenne Refinery reporting units after identifying a combination of events and circumstances that are indicators
of potential goodwill and long-lived asset impairment. The indicators included lower than typical gross margins during the summer
driving season, a decrease in the gross margin outlook and decrease in our market capitalization due to a decline in our common
share price.
Our testing first assessed the carrying values of our refining long-lived asset groups for recoverability. This entailed a comparison
of our reporting unit fair values relative to their respective carrying values. If carrying value exceeds fair value for a reporting
unit, we measure goodwill impairment as the excess of the carrying amount of reporting unit goodwill over the implied fair value
of that goodwill based on estimates of the fair value of all assets and liabilities in the reporting unit.
The estimated fair values of our goodwill reporting units and long-lived asset groups were derived using a combination of both
income and market approaches. The income approach reflects expected future cash flows based on estimates of future crack
spreads, forecasted production levels, operating costs and capital expenditures. Our market approaches include both the guideline
public company and guideline transaction methods. Both methods utilize pricing multiples derived from historical market
transactions of other like-kind assets. These fair value measurements involve significant unobservable inputs (Level 3 inputs).
As a result of our impairment testing during the second quarter of 2016, we determined that the carrying value of the long-lived
assets of the Cheyenne Refinery had been impaired and recorded long-lived asset impairment charges of $344.8 million.
Additionally, the carrying value of the Cheyenne Refinery’s goodwill was fully impaired and a goodwill impairment charge of
$309.3 million was also recorded, representing all of the goodwill allocated to our Cheyenne Refinery. Our interim testing did not
identify any other impairment.
We performed our annual goodwill impairment testing at July 1, 2016 and determined that the fair value of our El Dorado reporting
unit exceeded its carrying value by approximately 4%. Additionally, testing indicated no impairment of goodwill attributable to
our HEP reporting unit. The market outlook for future crack spreads has since improved and based on subsequent testing, the fair
value of the El Dorado reporting unit exceeded its carrying value by approximately 20% at December 31, 2016. A reasonable
expectation exists that future deterioration in gross margins could result in an impairment of goodwill and the long-lived assets
of the El Dorado reporting unit at some point in the future and such impairment charges could be material.
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.
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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.
As of December 31, 2016, we have the following notional contract volumes related to all outstanding derivative contracts used
to mitigate commodity price risk (all maturing in 2017):
Contract Description
Natural gas price swaps - long
Natural gas price swaps - short
Natural gas price swaps (basis spread) - long
Crude price swaps (basis spread) - long
WTI crude oil price swaps - long
WTI crude oil price swaps - short
Sub-octane gasoline price swaps - short
Sub-octane gasoline price swaps - long
NYMEX futures (WTI) - short
Forward gasoline and diesel contracts - long
Forward gasoline and diesel contracts - short
Physical crude contracts - short
Total Outstanding
Notional
Unit of
Measure
19,200,000 MMBTU
9,600,000 MMBTU
10,308,000 MMBTU
3,645,000 Barrels
829,000 Barrels
310,000 Barrels
829,000 Barrels
310,000 Barrels
755,000 Barrels
1,225,000 Barrels
175,000 Barrels
150,000 Barrels
At December 31, 2016, we had Canadian currency swap contracts that effectively fixed the conversion rate on $1.125 billion
Canadian dollars (the PCLI purchase price) at a USD / CAD exchange rate of 1.33. These swap contracts were settled on February
1, 2017, in connection with the closing of the PCLI acquisition.
The following sensitivity analysis provides the hypothetical effects of market price fluctuations to the commodity positions hedged
under our derivative contracts:
Commodity-based Derivative Contracts
2016
2015
Hypothetical 10% change in underlying commodity prices
$
(In thousands)
2,272
$
23,130
Estimated Change in Fair Value at December 31,
Interest Rate Risk Management
HEP uses interest rate swaps to manage its exposure to interest rate risk.
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As of December 31, 2016, HEP had two interest rate swap contracts with identical terms that hedge its exposure to the cash flow
risk caused by the effects of LIBOR changes on $150.0 million in credit agreement advances. The swaps 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, 2016, which equaled an effective interest rate of 2.99%. Both of these swap contracts mature in July 2017 and have
been designated as cash flow hedges.
The market risk inherent in our fixed-rate debt 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 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 this debt as of December 31, 2016 is presented below:
HollyFrontier Senior Notes
HEP Senior Notes
Outstanding
Principal
Estimated
Fair Value
(In thousands)
Estimated
Change in
Fair Value
$
$
1,000,000
700,000
$
$
1,022,500
723,750
$
$
40,022
18,662
For the variable rate HEP Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31,
2016, outstanding borrowings under the HEP Credit Agreement were $553.0 million. By means of its cash flow hedges, HEP has
effectively converted the variable rate on $150.0 million of outstanding principal to a weighted average fixed rate of 2.99%. For
the remaining unhedged Credit Agreement borrowings of $403.0 million, a hypothetical 10% change in interest rates applicable
to the HEP Credit Agreement would not materially affect cash flows.
At December 31, 2016, our marketable securities included investments in investment grade, highly-liquid investments with
maturities generally not greater than one year from the date of purchase and hence the interest rate market risk implicit in these
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”) and EBITDA excluding “non-
cash” lower of cost or market inventory valuation adjustments and goodwill and asset impairment charges (“Adjusted
EBITDA”) to amounts reported under generally accepted accounting principles in financial statements.
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Earnings before interest, taxes, depreciation and amortization, which we refer to as EBITDA, is calculated as net income (loss)
attributable to HollyFrontier stockholders plus (i) interest expense, net of interest income, (ii) income tax provision, and
(iii) depreciation and amortization. Adjusted EBITDA is calculated as EBITDA plus or minus (i) lower of cost or market inventory
valuation adjustment and (ii) goodwill and asset impairment charges. EBITDA and Adjusted EBITDA are not calculations provided
for under GAAP; however, the amounts included in these calculations are derived from amounts included in our consolidated
financial statements. EBITDA and Adjusted EBITDA should not be considered as alternatives 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 and
Adjusted EBITDA are not necessarily comparable to similarly titled measures of other companies. They are presented here because
they are widely used financial indicators used by investors and analysts to measure performance. EBITDA and Adjusted EBITDA
are also used by our management for internal analysis and as a basis for financial covenants.
Set forth below is our calculation of EBITDA and Adjusted EBITDA.
Years Ended December 31,
2015
2014
2016
(In thousands)
Net income attributable to HollyFrontier stockholders
Add income tax provision
Add interest expense (1)
Subtract interest income
Add depreciation and amortization
EBITDA
Add (subtract) lower of cost or market inventory adjustment
Add goodwill and asset impairment
PCLI pre-acquisition costs
Adjusted EBITDA
$
$
$
(260,453) $
19,411
80,910
(2,491)
363,027
200,404
(291,938)
654,084
13,406
575,956
$
$
740,101
406,060
44,840
(3,391)
346,151
1,533,761
226,979
—
—
1,760,740
$
$
$
281,292
141,172
51,323
(4,430)
363,381
832,738
397,478
—
—
1,230,216
(1) Includes loss on early extinguishment of debt of $8.7 million, $1.4 million and $7.7 million for the years ended December 31, 2016, 2015
and 2014, respectively.
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 non-cash effects of lower of cost or market
inventory valuation adjustments, goodwill and asset impairment charges or 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 (exclusive of lower of cost
or market inventory valuation adjustment) 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.
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Reconciliation of produced product sales to total sales and other revenues
Consolidated
Average sales price per produced barrel sold
Times sales of produced refined products (BPD)
Times number of days in period
Produced refined product sales
Total produced 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,
2015
2014
2016
(Dollars in thousands, except per barrel amounts)
$
$
$
$
58.02
435,420
366
9,246,283
9,246,283
624,233
9,870,516
436,974
159,700
10,467,190
402,043
168
(333,701)
10,535,700
$
$
$
$
71.32
438,000
365
11,401,928
11,401,928
1,214,920
12,616,848
352,113
202,222
13,171,183
358,875
663
(292,801)
13,237,920
$
$
$
$
110.19
420,990
365
16,931,944
16,931,944
1,566,925
18,498,869
1,060,354
147,002
19,706,225
332,626
2,103
(276,627)
19,764,327
Reconciliation of average cost of products per produced barrel sold to cost of products sold (exclusive of lower of cost or
market inventory valuation adjustment)
Consolidated
Average cost of products per produced barrel sold
Times sales of produced refined products (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 lower of cost or market inventory
valuation adjustment and depreciation and amortization)
Years Ended December 31,
2015
2014
2016
(Dollars in thousands, except per barrel amounts)
$
$
$
$
$
$
49.64
435,420
366
7,910,815
7,910,815
638,540
8,549,355
441,180
72,222
9,062,757
(296,830)
$
$
$
55.25
438,000
365
8,832,818
8,832,818
1,245,451
10,078,269
348,362
98,979
10,525,610
(286,392)
96.21
420,990
365
14,783,758
14,783,758
1,572,944
16,356,702
1,030,235
113,664
17,500,601
(272,216)
$
8,765,927
$
10,239,218
$
17,228,385
52
Table of Content
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 (BPD)
Times number of days in period
Refinery operating expenses for produced products sold
Total refinery operating expenses for 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,
2015
2014
2016
(Dollars in thousands, except per barrel amounts)
$
$
$
$
5.57
435,420
366
887,656
887,656
35,934
923,590
123,985
4,893
(33,629)
1,018,839
$
$
$
$
5.71
438,000
365
912,858
912,858
41,813
954,671
105,554
3,433
(3,285)
1,060,373
$
$
$
$
6.38
420,990
365
980,359
980,359
41,426
1,021,785
106,185
18,402
(1,432)
1,144,940
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
Produced refined product sales
Total produced 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,
2015
2014
2016
(Dollars in thousands, except per barrel amounts)
2.81
5.57
8.38
49.64
58.02
435,420
366
9,246,283
9,246,283
624,233
9,870,516
436,974
159,700
10,467,190
402,043
168
(333,701)
10,535,700
$
$
$
$
$
10.36
5.71
16.07
55.25
71.32
438,000
365
11,401,928
11,401,928
1,214,920
12,616,848
352,113
202,222
13,171,183
358,875
663
(292,801)
13,237,920
$
$
$
$
$
7.60
6.38
13.98
96.21
110.19
420,990
365
16,931,944
16,931,944
1,566,925
18,498,869
1,060,354
147,002
19,706,225
332,626
2,103
(276,627)
19,764,327
$
$
$
$
$
(1) We purchase finished products to facilitate delivery to certain locations 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 cost.
(3) Other refining segment revenue includes the incremental revenues associated with HFC Asphalt, product purchased and sold forward
for profit as market conditions and available storage capacity allows and miscellaneous revenue.
(4) Other refining segment cost of products sold includes the incremental cost of products for HFC Asphalt, the incremental cost associated
with storing product purchased and sold forward as market conditions and available storage capacity allows and miscellaneous costs.
(5) Other refining segment operating expenses include the marketing costs associated with our refining segment and the operating expenses
of HFC Asphalt.
53
Table of Content
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, 2016 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 (2013 framework). Based on this assessment, management concludes
that, as of December 31, 2016, 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, 2016. 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, 2016, based on criteria
established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (2013 framework) (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, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of HollyFrontier Corporation as of December 31, 2016 and 2015, 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,
2016 of HollyFrontier Corporation and our report dated February 22, 2017 expressed an unqualified opinion thereon.
/s/
ERNST & YOUNG LLP
Dallas, Texas
February 22, 2017
55
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2016 and 2015
Consolidated Statements of Income for the years ended
December 31, 2016, 2015 and 2014
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the years ended
December 31, 2016, 2015 and 2014
Consolidated Statements of Equity for the years ended
December 31, 2016, 2015 and 2014
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,
2016 and 2015, 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, 2016. 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, 2016 and 2015, and the consolidated results of its operations and its cash flows for
each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
HollyFrontier Corporation's internal control over financial reporting as of December 31, 2016, based on criteria established in
Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(2013 framework), and our report dated February 22, 2017 expressed an unqualified opinion thereon.
Dallas, Texas
February 22, 2017
/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: $3,657 and $15,013, respectively)
Marketable securities
Total cash, cash equivalents and short-term marketable securities
Accounts receivable: Product and transportation (HEP: $7,846 and $8,593, respectively)
Crude oil resales
Inventories: Crude oil and refined products
Materials, supplies and other (HEP: $1,402 and $1,972, respectively)
Income taxes receivable
Prepayments and other (HEP: $1,486 and $3,082, respectively)
Total current assets
Properties, plants and equipment, at cost (HEP: $1,702,703 and $1,631,845, respectively)
Less accumulated depreciation (HEP: $(337,135) and $(298,282), respectively)
Other assets: Turnaround costs
Goodwill (HEP: $288,991 and $288,991, respectively)
Intangibles and other (HEP: $208,975 and $128,583, respectively)
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (HEP: $10,518 and $10,948, respectively)
Income taxes payable
Accrued liabilities (HEP: $37,793 and $26,341, respectively)
Total current liabilities
Long-term debt (HEP: $1,243,912 and $1,008,752, respectively)
Deferred income taxes (HEP: $509 and $431, respectively)
Other long-term liabilities (HEP: $62,971 and $59,376, 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, 2016 and December 31, 2015
Additional capital
Retained earnings
Accumulated other comprehensive income (loss)
Common stock held in treasury, at cost – 78,617,600 and 75,728,478 shares as of
December 31, 2016 and December 31, 2015, respectively
Total HollyFrontier stockholders’ equity
Noncontrolling interest
Total equity
Total liabilities and equity
December 31,
2016
2015
$
$
$
710,579
424,148
1,134,727
449,036
30,163
479,199
970,361
165,315
1,135,676
68,371
33,036
2,851,009
5,546,856
(1,538,408)
4,008,448
217,340
2,022,463
336,401
2,576,204
9,435,661
935,387
—
147,842
1,083,229
2,235,137
620,414
194,896
66,533
144,019
210,552
323,858
28,120
351,978
712,865
129,004
841,869
—
43,666
1,448,065
5,490,189
(1,374,527)
4,115,662
231,873
2,331,781
260,918
2,824,572
8,388,299
716,490
8,142
135,983
860,615
1,040,040
497,906
179,965
—
—
2,560
4,026,805
2,776,728
10,612
(2,135,311)
4,681,394
620,591
5,301,985
9,435,661
$
2,560
4,011,052
3,271,189
(4,155)
(2,027,231)
5,253,415
556,358
5,809,773
8,388,299
$
$
$
$
Parenthetical amounts represent asset and liability balances attributable to Holly Energy Partners, L.P. (“HEP”) as of December 31, 2016 and December 31,
2015. HEP is a consolidated variable interest entity.
See accompanying notes.
58
Table of Content
HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)
Years Ended December 31,
2015
2014
2016
$
10,535,700
$
13,237,920
$
19,764,327
10,239,218
17,228,385
8,765,927
(291,938)
8,473,989
1,018,839
125,648
363,027
654,084
226,979
10,466,197
1,060,373
120,846
346,151
—
10,635,587
(99,887)
11,993,567
1,244,353
14,213
2,491
(72,192)
(8,718)
(7,441)
(71,647)
(171,534)
(79,181)
98,592
19,411
(190,945)
69,508
$
$
$
(260,453) $
(1.48) $
(1.48) $
176,101
176,101
(3,738)
3,391
(43,470)
(1,370)
9,402
(35,785)
1,208,568
552,196
(146,136)
406,060
802,508
62,407
740,101
3.91
3.90
188,731
188,940
$
$
$
397,478
17,625,863
1,144,940
114,609
363,381
—
19,248,793
515,534
(2,007)
4,430
(43,646)
(7,677)
866
(48,034)
467,500
334,834
(193,662)
141,172
326,328
45,036
281,292
1.42
1.42
197,243
197,428
Sales and other revenues
Operating costs and expenses:
Cost of products sold (exclusive of depreciation and amortization):
Cost of products sold (exclusive of lower of cost or market inventory
valuation adjustment)
Lower of cost or market inventory valuation adjustment
Operating expenses (exclusive of depreciation and amortization)
General and administrative expenses (exclusive of depreciation and
amortization)
Depreciation and amortization
Goodwill and asset impairment
Total operating costs and expenses
Income (loss) from operations
Other income (expense):
Earnings (loss) of equity method investments
Interest income
Interest expense
Loss on early extinguishment of debt
Other, net
Income (loss) before income taxes
Income tax provision:
Current
Deferred
Net income (loss)
Less net income attributable to noncontrolling interest
Net income (loss) attributable to HollyFrontier stockholders
Earnings (loss) per share attributable to HollyFrontier stockholders:
Basic
Diluted
Average number of common shares outstanding:
Basic
Diluted
See accompanying notes.
59
Table of Content
HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Net income (loss)
Other comprehensive income (loss):
Securities available-for-sale:
Unrealized gain (loss) on marketable securities
Reclassification adjustments to net income on sale or maturity of marketable
securities
Net unrealized gain (loss) on marketable securities
Hedging instruments:
Change in fair value of cash flow hedging instruments
Reclassification adjustments to net income on settlement of cash flow
hedging instruments
Amortization of unrealized loss attributable to discontinued cash flow
hedges
Net unrealized gain (loss) on hedging instruments
Other post-retirement benefit obligations:
Gain (loss) on post-retirement healthcare plan
Post-retirement healthcare plan gain reclassified to net income
Gain (loss) on retirement restoration plan
Retirement restoration plan loss reclassified to net income
Net change in other post-retirement benefit obligations
Other comprehensive income (loss) before income taxes
Income tax expense (benefit)
Other comprehensive income (loss)
Total comprehensive income (loss)
Less noncontrolling interest in comprehensive income (loss)
Years Ended December 31,
2016
2015
2014
$
(190,945) $
802,508
$
326,328
81
23
104
29
9
38
(153)
(4)
(157)
(17,625)
(5,847)
105,414
41,585
1,080
25,040
2,363
(3,482)
(9)
15
(1,113)
24,031
9,322
14,709
(176,236)
69,450
(47,492)
1,080
(52,259)
3,278
(3,299)
80
20
79
(52,142)
(20,237)
(31,905)
770,603
62,551
(50,682)
1,080
55,812
(7,434)
(4,296)
(615)
920
(11,425)
44,230
17,098
27,132
353,460
45,096
308,364
Comprehensive income (loss) attributable to HollyFrontier stockholders
$
(245,686) $
708,052
$
See accompanying notes.
60
Table of Content
HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Depreciation and amortization
Goodwill and asset impairment
Lower of cost or market inventory valuation adjustment
Net loss of equity method investments, inclusive of distributions
(Gain) loss on early extinguishment of debt
Gain on sale of assets
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
Purchase of equity method investment - HEP
Proceeds from sale of assets
Purchases of marketable securities
Sales and maturities of marketable securities
Other, net
Net cash used for investing activities
Cash flows from financing activities:
Borrowings under credit agreements
Repayments under credit agreements
Net proceeds from issuance of senior notes – HFC
Net proceeds from issuance of senior notes – HEP
Net proceeds from issuance of term loan
Repayment of term loan
Redemption of senior notes
Redemption of senior notes - HEP
Repayment of financing obligation
Net proceeds from common unit offerings - HEP
Purchase of treasury stock
Dividends
Distributions to noncontrolling interest
Excess tax benefit from equity-based compensation
Other, net
Net cash provided by (used for) financing activities
Cash and cash equivalents:
Increase (decrease) 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.
Years Ended December 31,
2015
2014
2016
$
(190,945) $
802,508
$
326,328
363,027
654,084
(291,938)
961
8,718
(72)
98,592
25,561
(12,155)
(127,221)
(1,869)
(68,371)
16,555
247,603
(8,142)
16,142
(125,254)
(3,005)
602,271
(372,195)
(107,595)
(42,627)
849
(546,632)
266,603
—
(801,597)
869,000
(1,028,000)
992,550
394,000
350,000
(350,000)
—
—
(39,500)
125,870
(133,430)
(234,004)
(92,607)
—
(10,507)
843,372
346,151
—
226,979
8,613
(3,788)
(8,677)
(146,136)
30,367
38,525
238,392
(33,717)
11,719
13,291
(406,339)
(11,500)
(6,924)
(89,365)
(30,473)
979,626
(483,034)
(193,121)
(55,032)
19,264
(509,338)
839,513
—
(381,748)
973,900
(832,900)
—
—
—
—
(155,156)
—
—
—
(742,823)
(246,908)
(83,268)
—
(12,175)
(1,099,330)
(501,452)
567,985
66,533
46,442
586,447
$
$
$
363,381
—
397,478
5,257
1,489
(866)
(193,662)
29,598
(22,668)
108,876
(78,842)
94,237
1,486
(217,541)
19,642
8,047
(96,803)
13,159
758,596
(366,135)
(198,686)
—
16,633
(1,025,602)
1,276,447
5,021
(292,322)
642,300
(434,300)
—
—
—
—
—
(156,188)
—
—
(158,847)
(647,197)
(78,202)
2,040
(7,998)
(838,392)
(372,118)
940,103
567,985
55,716
237,907
644,046
66,533
710,579
54,074
40,236
$
$
$
$
$
$
61
Table of Content
HOLLYFRONTIER CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
HollyFrontier Stockholders' Equity
Balance at December 31, 2013
$
2,560
$ 3,990,630
$3,144,480
$
822
$ (1,138,872) $
609,778
$
6,609,398
Common
Stock
Additional
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Treasury
Stock
Non-
controlling
Interest
Total Equity
Net income
Dividends
Distributions to noncontrolling interest
holders
Other comprehensive income, net of tax
Issuance of common stock under incentive
compensation plans, net of forfeitures
Equity-based compensation, inclusive of
tax benefit
Purchase of treasury stock
Purchase of HEP units for restricted grants
Other
Balance at December 31, 2014
Net income
Dividends
Distributions to noncontrolling interest
holders
Other comprehensive income (loss), net of
tax
Issuance of common stock under incentive
compensation plans, net of forfeitures
Equity-based compensation, inclusive of
tax benefit
Purchase of treasury stock
Purchase of HEP units for restricted grants
Other
Balance at December 31, 2015
Net income (loss)
Dividends
Distributions to noncontrolling interest
holders
Other comprehensive income (loss), net of
tax
Equity attributable to HEP common unit
issuances, net of tax
Issuance of common stock under incentive
compensation plans, net of forfeitures
Equity-based compensation, inclusive of
tax benefit
Purchase of treasury stock
Purchase of HEP units for restricted grants
Other
Balance at December 31, 2016
See accompanying notes.
—
—
—
—
—
—
—
—
—
—
—
—
—
(15,101)
28,099
—
—
—
281,292
(647,195)
—
—
—
—
—
—
—
—
—
—
27,072
—
—
—
—
—
—
—
—
—
15,101
—
(165,304)
—
—
45,036
—
(78,202)
60
—
3,539
—
(3,577)
501
326,328
(647,195)
(78,202)
27,132
—
31,638
(165,304)
(3,577)
501
$
2,560
$ 4,003,628
$2,778,577
$
27,894
$ (1,289,075) $
577,135
$
6,100,719
—
—
—
—
—
—
—
—
—
—
—
—
—
(14,958)
22,382
—
—
—
740,101
(247,489)
—
—
—
—
—
—
—
—
—
—
(32,049)
—
—
—
—
—
—
—
—
—
14,958
—
(753,114)
—
—
62,407
—
802,508
(247,489)
(83,268)
(83,268)
144
—
3,483
—
(3,555)
12
(31,905)
—
25,865
(753,114)
(3,555)
12
$
2,560
$ 4,011,052
$3,271,189
$
(4,155) $ (2,027,231) $
556,358
$
5,809,773
—
—
—
—
—
—
—
—
—
—
—
—
—
—
23,110
(25,982)
18,625
—
—
—
(260,453)
(234,008)
—
—
—
—
—
—
—
—
—
—
—
14,767
—
—
—
—
—
—
—
—
—
—
—
69,508
—
(190,945)
(234,008)
(92,607)
(92,607)
(58)
14,709
88,166
111,276
25,982
—
—
—
(134,062)
—
—
2,727
—
(3,521)
18
21,352
(134,062)
(3,521)
18
$
2,560
$ 4,026,805
$2,776,728
$
10,612
$ (2,135,311) $
620,591
$
5,301,985
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 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, 2016, 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 HollyFrontier Asphalt Company (“HFC Asphalt”) which operates various asphalt terminals in
Arizona, New Mexico and Oklahoma; and
owned a 37% interest in HEP, a consolidated variable interest entity (“VIE”), which includes our 2% general partner
interest.
On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a share purchase agreement with Suncor
Energy Inc. (“Suncor”) to acquire 100% of the outstanding capital stock of Petro-Canada Lubricants Inc. (“PCLI”) that closed on
February 1, 2017. See Note 2 for additional information.
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 Entities: 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 financial performance, and therefore we consolidate HEP.
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.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
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.
Balance Sheet Offsetting: We purchase and sell inventories of crude oil with certain same-parties that are net settled in accordance
with contractual net settlement provisions. Our policy is to present such balances on a net basis 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.
Accounts Receivable: Our accounts receivable consist of amounts due from customers that are primarily companies in the petroleum
industry. Credit is extended based on our 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 our historical loss experience 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 $2.3 million at both
December 31, 2016 and 2015.
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 and unfinished
and finished refined products, 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 replacement costs. 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.
Inventories consisting of process chemicals, materials and maintenance supplies and RINs are stated at the lower of weighted-
average cost or market.
At December 31, 2016, and 2015, market values had fallen below historical LIFO inventory costs and, as a result, we recorded
lower of cost or market inventory valuation reserves of $332.5 million and $624.5 million, respectively.
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 13 for additional information.
Properties, plants and equipment: Properties, plants and equipment are stated at cost. Depreciation is provided by the straight-
line method over the estimated useful lives of the assets, primarily 15 to 32 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.
64
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
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. Certain of our refining assets have no recorded liability for asset retirement obligations
since the timing of any retirement and related costs are currently indeterminable.
Our asset retirement obligations were $22.1 million and $20.7 million at December 31, 2016 and 2015, respectively, which are
included in “Other long-term liabilities” in our consolidated balance sheets. Accretion expense was insignificant for the years
ended December 31, 2016, 2015 and 2014.
Intangibles, Goodwill and long-lived assets: Intangible assets are assets (other than financial assets) that lack physical substance,
and 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 intangibles 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.
Our long-lived assets principally consist of our refining assets that are organized as refining asset groups. These refinery asset
groups also constitute our individual refinery reporting units that are used for testing and measuring goodwill impairments. Our
long-lived assets are evaluated for 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
measured, if any, is equal to the amount by which the asset group’s carrying value exceeds its fair value.
See Note 10 for information regarding goodwill and long-lived asset impairment charges recorded during the year ended
December 31, 2016.
Our consolidated HEP assets include a third-party transportation agreement, an intangible asset, that currently generates minimum
annual cash inflows of $26.0 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 $36.5 million and $38.5 million at December 31, 2016, and 2015, respectively, and is presented net
of accumulated amortization of $23.7 million and $21.7 million respectively, in “Intangibles and other” in our consolidated balance
sheets.
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% or a controlling interest with respect to VIE's, and use the equity method of accounting for investments
in which we have a noncontrolling interest, yet have have significant influence over the entity. 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 50% joint venture interest in Frontier Aspen LLC, the owner of a pipeline running from Wyoming to Frontier Station,
Utah (the “Frontier Pipeline”); a 50% interest in Osage Pipe Line Company, LLC, the owner of a pipeline running from Cushing,
Oklahoma to El Dorado, Kansas (the “Osage Pipeline”); a 50% interest in Cheyenne Pipeline, LLC, the owner of a pipeline running
from Fort Laramie, Wyoming to Cheyenne, Wyoming (the “Cheyenne Pipeline”); and a 25% joint venture interest in SLC Pipeline,
LLC, the owner of a pipeline (the “SLC Pipeline”) that serves refineries in the Salt Lake City, Utah area, that are accounted for
using the equity method of accounting. As of December 31, 2016, HEP's underlying equity and recorded investment balances in
the joint ventures are $109.3 million and $165.6 million, respectively. The differences are being amortized as adjustments to HEP's
pro-rata share of earnings in the joint ventures.
65
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
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.
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 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. Deferred
turnaround and catalyst amortization expense was $110.6 million, $107.8 million and $96.9 million for the years ended
December 31, 2016, 2015 and 2014, respectively.
Environmental Costs: Environmental costs are charged to operating expenses if they relate to an existing condition caused by
past operations. We have ongoing investigations of environmental matters at various locations as part of our assessment process
to determine the amount of environmental obligation we may have, if any, with respect to these matters for which we have recorded
the estimated cost of the studies. 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 are undiscounted and require
judgment with respect to costs, time frame 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 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.
For the year ended December 31, 2016, we recorded an income tax expense of $19.4 million compared $406.1 million and $141.2
million for the years ended December 31, 2015 and 2014, respectively. This decrease was due principally to a pre-tax loss during
the year ended December 31, 2016 compared to pre-tax earnings in the same periods of 2015 and 2014. Our effective tax rates,
before consideration of earnings attributable to the noncontrolling interest, were (11.3)%, 33.6% and 30.2% for the years ended
December 31, 2016, 2015 and 2014, respectively. The year-over-year decrease in the effective tax rate in 2016 was due principally
to the effects of the second quarter $309.3 million goodwill impairment charge, a significant cause of our $171.5 million loss
before income taxes for the year ended December 31, 2016, that is not deductible for income tax purposes.
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.
66
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Inventory Repurchase Obligations: We periodically enter into same-party sell / buy transactions, whereby we sell certain refined
product inventory and subsequently repurchase the inventory in order to facilitate delivery to certain locations. Such sell / buy
transactions are accounted for as inventory repurchase obligations under which proceeds received under the initial sell is recognized
as an inventory repurchase obligation that is subsequently reversed when the inventory is repurchased. For the years ended December
31, 2016, 2015 and 2014, we received proceeds of $57.0 million, $115.4 million and $77.3 million and subsequently repaid $58.0
million, $115.3 million and $78.1 million, respectively, under these sell / buy transactions.
New Accounting Pronouncements
Share-Based Compensation
In March 2016, Accounting Standard Update (“ASU”) 2016-09, “Improvements to Employee Share-Based Payment Accounting,”
was issued which simplifies the accounting for employee share-based payment transactions, including the accounting for income
taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. This standard
is effective January 1, 2017. We do not expect this standard to have a material impact on our financial condition, results of operations
and cash flows.
Leases
In February 2016, ASU 2016-02, “Leases,” was issued requiring leases to be measured and recognized as a lease liability, with a
corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we are evaluating
the impact of this standard.
Consolidation
In February 2015, ASU 2015-02, “Consolidation,” was issued to improve consolidation guidance for certain legal entities. It
modifies the evaluation of whether limited partnerships and similar legal entities are VIEs or voting interest entities, eliminates
the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting
entities involved with VIEs, particularly those that have fee arrangements and related party provisions and provides a scope
exception from consolidation guidance for certain reporting entities that comply with or operate in accordance with requirements
that are similar to those included in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. We
adopted this standard effective January 1, 2016, which had no affect our financial position or results of operations.
Revenue Recognition
In May 2014, ASU 2014-09, “Revenue from Contracts with Customers” was issued requiring revenue to be recognized when
promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or
services. This standard has an effective date of January 1, 2018, and we anticipate to account for the new guidance using the
modified retrospective implementation method, whereby a cumulative effect adjustment is recorded to retained earnings as of the
date of initial application. Our preparation for adoption of this standard is in progress, and we are currently evaluating terms,
conditions and our performance obligations of our existing contracts with customers. We are evaluating the effect of this standard
on our revenue recognition policies and whether it will have a material impact on our financial condition, results of operations or
cash flows.
NOTE 2:
PCLI Acquisition
On October 29, 2016, our wholly-owned subsidiary, 9952110 Canada Inc., entered into a share purchase agreement with Suncor
to acquire 100% of the outstanding capital stock of PCLI that closed on February 1, 2017. Cash consideration paid was $862.1
million, or $1.125 billion in Canadian dollars.
PCLI is located in Mississauga, Ontario and is a producer of base oils in Canada with a plant having 15,600 BPD of lubricant
production capacity. The facility is downstream integrated from base oils to finished lubricants and produces a broad spectrum of
specialty lubricants and white oils that are distributed to end customers worldwide.
67
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
This acquisition will be accounted for as business combination, with the $862.1 million cash purchase price plus the fair value of
additional consideration allocated to the the acquisition date fair value of assets and liabilities acquired. Due to the short timeframe
between the closing of this acquisition and filing of this Annual Report on Form 10-K, we have not completed the detailed valuation
studies necessary to arrive at the required fair value estimates of the acquired PCLI assets, liabilities assumed and related purchase
price allocations.
NOTE 3: Holly Energy Partners
HEP, a consolidated VIE, is a publicly held master limited partnership that owns and operates logistic assets consisting of petroleum
product and crude oil pipelines, terminals, tankage, loading rack facilities and refinery processing units 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, LLC (“UNEV”),
the owner of pipeline running from Woods Cross, Utah to Las Vegas, Nevada (the “UNEV Pipeline”) and associated product
terminals; a 50% ownership interest in each of the Frontier Pipeline, the Osage Pipeline and the Cheyenne Pipeline; and a 25%
interest in the SLC Pipeline.
As of December 31, 2016, we owned a 37% interest in HEP, including the 2% general partner interest. As the general partner of
HEP, we have the sole ability to direct the activities that most significantly impact HEP's financial performance, and therefore we
consolidate HEP.
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 83% of HEP’s total revenues for the year ended December 31, 2016. 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. HEP’s creditors have no recourse
to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries. See Note 12 for
a description of HEP’s debt obligations.
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.
Woods Cross Assets
On October 3, 2016, HEP acquired from us all the membership interests of Woods Cross Operating LLC, which owns the crude
unit, FCCU and polymerization unit of the first phase of our Woods Cross Refinery expansion project that was completed in the
second quarter of 2016, for cash consideration of approximately $278.0 million.
In connection with this transaction, we entered into 15-year tolling agreements containing minimum quarterly throughput
commitments that provide minimum annualized payments to HEP of $56.7 million.
Cheyenne Pipeline
On June 3, 2016, HEP acquired a 50% interest in Cheyenne Pipeline LLC, owner of the Cheyenne Pipeline, in exchange for a
contribution of $42.6 million in cash to Cheyenne Pipeline LLC. Cheyenne Pipeline will continue to be operated by an affiliate
of Plains All American Pipeline, L.P. (“Plains”), which owns the remaining 50% interest. The 87-mile crude oil pipeline runs from
Fort Laramie, Wyoming to Cheyenne, Wyoming and has an 80,000 BPD capacity.
Tulsa Tanks
On March 31, 2016, HEP acquired crude oil tanks located at our Tulsa Refineries from Plains for $39.5 million. Previously in
2009, we sold these tanks to Plains and leased them back, and due to our continuing interest in the tanks, we accounted for the
transaction as a financing arrangement. Accordingly, the tanks remained on our balance sheet and were depreciated for accounting
purposes, and the proceeds received from Plains were recorded as a financing obligation and presented as a component of outstanding
debt.
In accounting for HEP’s March 2016 purchase from Plains, the amount paid was recorded against our outstanding financing
obligation balance of $30.8 million, with the excess $8.7 million payment resulting in a loss on early extinguishment of debt.
68
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Magellan Asset Exchange
On February 22, 2016, we obtained a 50% membership interest in Osage Pipe Line Company, LLC (“Osage”) in exchange for a
20-year terminalling services agreement, whereby, a subsidiary of Magellan Midstream Partners (“Magellan Midstream”) will
provide terminalling services for all of our products originating in Artesia, New Mexico that require terminalling in or through El
Paso, Texas. Under the agreement, we will be charged tariffs based on the volumes of refined product processed. Osage is the
owner of the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to our El Dorado Refinery in
Kansas and also has a connection to the Jayhawk pipeline that services the CHS refinery in McPherson, Kansas. This exchange
was accounted for at fair value, whereby the 50% membership interest in the Osage Pipeline was recorded at appraised fair value
and an offsetting residual deferred credit in the amount of $38.9 million was recorded, which will be amortized to cost of products
sold over the 20-year service period. No gain or loss was recorded for this exchange.
Also on February 22, 2016, we contributed the 50% membership interest in Osage to HEP, and in exchange received HEP's El
Paso terminal. Pursuant to this exchange, HEP agreed to build two connections to Magellan Midstream's El Paso terminal. In
addition, HEP agreed to become the operator of the Osage Pipeline. This exchange was accounted for at carry-over basis with no
resulting gain or loss.
El Dorado Asset Transaction
On November 1, 2015, HEP acquired from us newly constructed naphtha fractionation and hydrogen generation units at our El
Dorado Refinery for cash consideration of $62.0 million. In connection with this transaction, we entered into 15-year tolling
agreements containing minimum quarterly throughput commitments that provide minimum annualized payments to HEP of $15.1
million.
Frontier Pipeline Transaction
On August 31, 2015, HEP purchased a 50% interest in Frontier Aspen LLC (previously known as Frontier Pipeline Company),
owner of the Frontier Pipeline, from an affiliate of Enbridge, Inc. for $55.0 million. Frontier Pipeline will continue to be operated
by an affiliate of Plains, which owns the remaining 50% interest. The 289-mile crude oil pipeline runs from Casper, Wyoming to
Frontier Station, Utah, has a 72,000 BPD capacity and supplies Canadian and Rocky Mountain crudes to Salt Lake City area
refiners through a connection to the SLC Pipeline.
Transportation Agreements
HEP serves our refineries under long-term pipeline, terminal and tankage throughput agreements and refinery processing tolling
agreements expiring from 2019 through 2036. Under these agreements, we pay HEP fees to transport, store and process throughput
volumes of refined products, crude oil and feedstocks on HEP's pipelines, terminals, tankage, loading rack facilities and refinery
processing units 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 or Federal Energy Regulatory Commission index. As of December 31, 2016, these
agreements result in minimum annualized payments to HEP of $321.0 million.
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's recent common unit issuances (2014 through present) are summarized below:
HEP Private Placement Agreement
On September 16, 2016, HEP entered into a common unit purchase agreement in which certain purchasers agreed to purchase in
a private placement 3,420,000 HEP common units, representing limited partnership interests, at a price of $30.18 per common
unit. The private placement closed on October 3, 2016, at which time HEP received proceeds of approximately $103 million, which
were used to finance a portion of the Woods Cross assets acquisition. In connection with this private placement and to maintain
our 2% general partner interest in HEP, we made capital contributions totaling $2.1 million to HEP in October 2016. After this
common unit issuance, our interest in HEP is 37%, including the 2% general partner interest.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
HEP Common Unit Continuous Offering Program
On May 10, 2016, HEP established a continuous offering program under which HEP may issue and sell common units from time
to time, representing limited partner interests, up to an aggregate gross sales amount of $200 million. As of December 31, 2016,
HEP has issued 703,455 units under this program, providing $23.0 million in net proceeds. In connection with this program and
to maintain our 2% general partner interest in HEP, we made capital contributions totaling $0.5 million as of December 31, 2016.
HEP intends to use the net proceeds for general partnership purposes, which may include funding working capital, repayment of
debt, acquisitions and capital expenditures. Amounts repaid under HEP’s credit facility may be reborrowed from time to time.
As a result of this transaction and resulting HEP ownership changes, we adjusted additional capital and equity attributable to HEP's
noncontrolling interest holders to reallocate HEP's equity among its unitholders.
NOTE 4:
Fair Value Measurements
Our financial instruments measured at fair value on a recurring basis consist of investments in marketable securities and derivative
instruments.
Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability,
including assumptions about risk). GAAP categorizes inputs used in fair value measurements into three broad levels as follows:
•
•
•
(Level 1) Quoted prices in active markets for identical assets or liabilities.
(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and
liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable
market data.
(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value
of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.
The carrying values of marketable securities and derivative instruments at December 31, 2016 and December 31, 2015 were as
follows:
Financial Instrument
December 31, 2016
Assets:
Marketable securities
Commodity price swaps
Commodity forward contracts
HEP interest rate swaps
Total assets
Liabilities:
NYMEX futures contracts
Commodity price swaps
Commodity forward contracts
Foreign currency forward contracts
Total liabilities
Carrying
Amount
Level 1
Fair Value by Input Level
Level 2
(In thousands)
Level 3
$
$
$
$
424,148
14,563
5,905
91
444,707
1,975
26,845
8,316
6,519
43,655
$
$
$
$
— $
—
—
—
— $
1,975
—
—
—
1,975
$
$
424,148
14,358
5,905
91
444,502
$
$
— $
24,086
8,316
6,519
38,921
$
—
205
—
—
205
—
2,759
—
—
2,759
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Financial Instrument
December 31, 2015
Assets:
Marketable securities
NYMEX futures contract
Commodity price swaps
HEP interest rate swaps
Total assets
Liabilities:
Commodity price swaps
HEP interest rate swaps
Total liabilities
Carrying
Amount
Fair Value by Input Level
Level 1
Level 2
Level 3
(In thousands)
$
$
$
$
144,019
3,469
37,097
304
184,889
98,930
114
99,044
$
$
$
$
— $
3,469
—
—
3,469
$
— $
—
— $
144,019
—
37,097
304
181,420
98,930
114
99,044
$
$
$
$
—
—
—
—
—
—
—
—
Level 1 Financial Instruments
Our NYMEX futures contracts are exchange traded and are measured and recorded at fair value using quoted market prices, a
Level 1 input.
Level 2 Financial Instruments
Investments in marketable securities, derivative instruments consisting of commodity price swaps and forward sales and purchase
contracts and HEP's interest rate swaps are measured and recorded at fair value using Level 2 inputs. The fair values of the
commodity price and interest rate swap contracts are 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 securities 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 unleaded gasoline, and at times have forward commodity
sales and purchase contracts, for which quoted forward market prices are not readily available. The forward rate used to value
these price swaps and forward sales and purchase contracts are 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 derivative instruments)
for the years ended December 31, 2016 and 2015:
Level 3 Financial Instruments
Liability 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
Liability balance at end of period
Years Ended December 31,
2016
2015
(In thousands)
— $
(1,460)
(1,094)
—
(2,554) $
—
3,852
—
(3,852)
—
$
$
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 $0.3 million.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
During the year ended December 31, 2016, we recognized goodwill and long-lived asset impairment charges based on fair value
measurements (see Note 10). Also, we recognized a non-recurring fair value measurement of $44.4 million that relates to HEP’s
equity interest in Osage in February 2016. The fair value measurements were based on a combination of valuation methods including
discounted cash flows, and the guideline public company and guideline transaction methods, Level 3 inputs.
NOTE 5: Earnings Per Share
Basic earnings per share is calculated as net income (loss) 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 restricted shares and performance share units. The following is a reconciliation of the denominators of the basic and
diluted per share computations for net income (loss) attributable to HollyFrontier stockholders:
Net income (loss) attributable to HollyFrontier stockholders
Participating securities’ (restricted stock) share in earnings
Net income (loss) attributable to common shares
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 (loss) per share
Diluted earnings (loss) per share
$
$
$
$
2016
Years Ended December 31,
2015
(In thousands, except per share data)
2014
(260,453) $
1,003
(261,456) $
176,101
—
$
$
740,101
2,306
737,795
188,731
209
281,292
820
280,472
197,243
185
176,101
188,940
197,428
(1.48) $
(1.48) $
3.91
3.90
$
$
1.42
1.42
356
(1) Excludes anti-dilutive restricted and performance share units of:
469
89
NOTE 6:
Stock-Based Compensation
As of December 31, 2016, we have two principal share-based compensation plans (collectively, the “Long-Term Incentive
Compensation Plan”).
The compensation cost charged against income for these plans was $22.8 million, $26.9 million and $26.1 million for the years
ended December 31, 2016, 2015 and 2014, respectively. Our accounting policy for the recognition of compensation expense for
awards with pro-rata vesting is to expense the costs ratably over the vesting periods.
Additionally, HEP maintains a share-based compensation plan for Holly Logistic Services, L.L.C.'s non-employee directors and
certain executives and employees. Compensation cost attributable to HEP’s share-based compensation plan was $2.7 million, $3.5
million and $3.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Restricted Stock and Restricted Stock Units
Under our Long-Term Incentive Compensation Plan, we grant certain officers and other key employees restricted stock and
restricted stock unit awards with awards generally vesting over a period of one to three years. Restricted stock award recipients
are generally entitled to all the rights of absolute ownership of the restricted shares from the date of grant including the right to
vote the shares and to receive dividends. Upon vesting, restrictions on the restricted shares lapse at which time they convert to
common shares. In addition, we grant non-employee directors restricted stock unit awards, which typically vest over a period of
one year and are payable in stock. The fair value of each restricted stock and restricted stock unit award is measured based on the
grant date market price of our common shares 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 and restricted stock unit activity and changes during the year ended December 31, 2016 is presented
below:
Restricted Stock and Restricted Stock Units
Grants
Weighted
Average Grant
Date Fair
Value
Aggregate
Intrinsic Value
($000)
Outstanding at January 1, 2016 (non-vested)
Granted
Vesting (transfer/conversion to common stock)
Forfeited
Outstanding at December 31, 2016 (non-vested)
722,525
894,879
(409,016)
(19,614)
1,188,774
$
$
47.50
21.66
45.09
48.02
28.87
$
37,426
For the years ended December 31, 2016, 2015 and 2014, restricted stock and restricted stock units vested having a grant date fair
value of $18.4 million, $14.2 million and $18.2 million, respectively. For the years ended December 31, 2015 and 2014, we granted
restricted stock and restricted stock units having a weighted average grant date fair value of $49.92 and $42.03, respectively. As
of December 31, 2016, there was $24.2 million of total unrecognized compensation cost related to non-vested restricted stock and
restricted stock unit grants. That cost is expected to be recognized over a weighted-average period of 2.5 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 “financial performance” and “market performance”
criteria. Financial performance is based on our financial performance compared to a peer group of independent refining companies,
while market performance is based on the relative standing of total shareholder return achieved by HollyFrontier compared to
peer group companies. The number of shares ultimately issued under these awards can range from zero to 200% of target award
amounts. As of December 31, 2016, estimated share payouts for outstanding non-vested performance share unit awards averaged
approximately 67% of target amounts.
A summary of performance share unit activity and changes during the year ended December 31, 2016 is presented below:
Performance Share Units
Outstanding at January 1, 2016 (non-vested)
Granted
Vesting and transfer of ownership to recipients
Forfeited
Outstanding at December 31, 2016 (non-vested)
Grants
637,938
376,275
(161,610)
(148,664)
703,939
For the year ended December 31, 2016, we issued 76,404 shares of common stock, representing a 47% payout on vested performance
share units having a grant date fair value of $7.4 million. For the years ended December 31, 2015 and 2014, we issued common
stock upon the vesting of the performance share units having a grant date fair value of $10.4 million and $14.3 million, respectively.
As of December 31, 2016, there was $14.5 million of total unrecognized compensation cost related to non-vested performance
share units having a grant date fair value of $33.79 per unit. That cost is expected to be recognized over a weighted-average period
of 2.3 years.
NOTE 7: Cash and Cash Equivalents and Investments in Marketable Securities
Our investment portfolio at December 31, 2016 consisted of cash, cash equivalents and investments in marketable securities.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
We currently invest in marketable debt securities with the maximum maturity or put date of any individual issue generally not
greater than one year from the date of purchase, which are usually held until maturity. All of these instruments are classified as
available-for-sale and are reported at fair value. 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.
Unrealized gains and losses on our available-for-sale securities are due to changes in market prices and are considered temporary.
The following is a summary of our marketable securities as of December 31, 2016 and 2015, respectively:
December 31, 2016
Commercial paper
Corporate debt securities
State and political subdivisions debt securities
Total marketable securities
December 31, 2015
Commercial paper
Corporate debt securities
State and political subdivisions debt securities
Total marketable securities
Amortized Cost
Gross
Unrealized
Gain
Gross
Unrealized Loss
Fair Value
(Net Carrying
Amount)
(In thousands)
$
$
$
$
7,687
4,001
412,462
424,150
22,876
32,311
88,935
144,122
$
$
$
$
1
—
1
2
1
—
6
7
$
$
$
$
(1) $
—
(3)
(4) $
(2) $
(41)
(67)
(110) $
7,687
4,001
412,460
424,148
22,875
32,270
88,874
144,019
Interest income recognized on our marketable securities was $0.8 million, $1.9 million and $2.2 million for the years ended
December 31, 2016, 2015 and 2014, respectively.
NOTE 8:
Inventories
Inventory consists of the following components:
Crude oil
Other raw materials and unfinished products(1)
Finished products(2)
Lower of cost or market reserve
Process chemicals(3)
Repairs and maintenance supplies and other (4)
Total inventory
December 31,
2016
2015
(In thousands)
$
$
549,886
287,561
465,432
(332,518)
2,767
162,548
$
1,135,676
$
518,922
214,832
603,568
(624,457)
4,477
124,527
841,869
(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.
(4) Includes RINs
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Inventories which are valued at the lower of LIFO cost or market reflect a valuation reserve of $332.5 million and $624.5 million
at December 31, 2016 and 2015, respectively. The December 31, 2015 market reserve of $624.5 million was reversed due to the
sale of inventory quantities that gave rise to the 2015 reserve. A new market reserve of $332.5 million was established as of
December 31, 2016 based on market conditions and prices at that time. The effect of the change in the lower of cost or market
reserve was a decrease to cost of goods sold of $291.9 million for the year ended December 31, 2016 and an increase of $227.0
million and $397.5 million for the years ended December 31, 2015 and 2014, respectively.
At December 31, 2016, 2015 and 2014, the LIFO value of inventory, net of the lower of cost or market reserve, was equal to current
costs.
NOTE 9:
Properties, Plants and Equipment
The components of properties, plants and equipment are as follows:
December 31,
2016
2015
(In thousands)
Land, buildings and improvements
$
326,097
$
Refining facilities
Pipelines and terminals
Transportation vehicles
Other fixed assets
Construction in progress
Accumulated depreciation
3,382,369
1,392,898
18,841
153,463
273,188
305,712
2,833,125
1,321,398
21,289
158,401
850,264
5,546,856
(1,538,408)
4,008,448
$
5,490,189
(1,374,527)
4,115,662
$
During the year ended December 31, 2016, we recorded impairment charges of $308.3 million that are attributable to properties,
plant and equipment of our Cheyenne reporting unit. See Note 10 for additional information.
We capitalized interest attributable to construction projects of $8.0 million, $5.5 million and $11.8 million for the years ended
December 31, 2016, 2015 and 2014, respectively.
Depreciation expense was $247.9 million, $233.3 million and $261.8 million for the years ended December 31, 2016, 2015 and
2014, respectively. For the years ended December 31, 2016, 2015 and 2014, depreciation expense included $62.7 million, $58.7
million and $58.1 million, respectively, attributable to HEP operations.
NOTE 10: Goodwill and Long-lived Asset Impairment
As of December 31, 2016, our goodwill balance was $2.0 billion, with goodwill assigned to our refining and HEP segments of
$1.7 billion and $0.3 billion, respectively.
During the second quarter of 2016, we performed interim goodwill impairment and related long-lived asset impairment testing of
our El Dorado and Cheyenne Refinery reporting units after identifying a combination of events and circumstances that are indicators
of potential goodwill and long-lived asset impairment. The indicators included lower than typical gross margins during the summer
driving season, a decrease in the gross margin outlook and decrease in our market capitalization due to a decline in our common
share price.
Our testing first assessed the carrying values of our refining long-lived asset groups for recoverability. This entailed a comparison
of our reporting unit fair values relative to their respective carrying values. If carrying value exceeds fair value for a reporting
unit, we measure goodwill impairment as the excess of the carrying amount of reporting unit goodwill over the implied fair value
of that goodwill based on estimates of the fair value of all assets and liabilities in the reporting unit.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The estimated fair values of our goodwill reporting units and long-lived asset groups were derived using a combination of both
income and market approaches. The income approach reflects expected future cash flows based on estimates of future crack
spreads, forecasted production levels, operating costs and capital expenditures. Our market approaches include both the guideline
public company and guideline transaction methods. Both methods utilize pricing multiples derived from historical market
transactions of other like-kind assets. These fair value measurements involve significant unobservable inputs (Level 3 inputs).
As a result of our impairment testing during the second quarter of 2016, we determined that the carrying value of the long-lived
assets of the Cheyenne Refinery had been impaired and recorded long-lived asset impairment charges of $344.8 million that
principally related to properties, plant and equipment. Additionally, the carrying value of the Cheyenne Refinery’s goodwill was
fully impaired and a goodwill impairment charge of $309.3 million was also recorded, representing all of the goodwill allocated
to our Cheyenne Refinery. Our interim testing did not identify any impairment related to our El Dorado reporting unit.
We performed our annual goodwill impairment testing at July 1, 2016 and determined that the fair value of our El Dorado reporting
unit exceeded its carrying value by approximately 4%. Additionally, testing indicated no impairment of goodwill attributable to
our HEP reporting unit. The market outlook for future crack spreads has since improved and based on subsequent testing, the fair
value of the El Dorado reporting unit exceeded its carrying value by approximately 20% at December 31, 2016. A reasonable
expectation exists that future deterioration in gross margins could result in an impairment of goodwill and the long-lived assets
of the El Dorado reporting unit at some point in the future and such impairment charges could be material.
As of December 31, 2016, accumulated goodwill losses recognized totaled $309.3 million, all of which relates to our Refining
segment. There were no impairments of goodwill or long-lived assets during the years ended December 31, 2015 and 2014.
NOTE 11: Environmental
We expensed $6.6 million, $14.7 million and $28.5 million for the years ended December 31, 2016, 2015 and 2014, respectively,
for environmental remediation obligations. The accrued environmental liability reflected in our consolidated balance sheets was
$96.4 million and $98.1 million at December 31, 2016 and 2015, respectively, of which $82.9 million and $83.5 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). The amount of our accrued liability could increase
in the future when the results of ongoing investigations become known, are considered probable and can be reasonably estimated.
NOTE 12: Debt
HollyFrontier Credit Agreement
We have a $1 billion senior unsecured revolving credit facility maturing in July 2019 (the “HollyFrontier Credit Agreement”) that
was amended in February 2017, increasing the size of the credit facility to $1.35 billion and extending the maturity to February
2022. The HollyFrontier Credit Agreement may be used for revolving credit loans and letters of credit from time to time and is
available to fund general corporate purposes. During the year ended December 31, 2016, we received advances totaling $315.0
million and repaid $315.0 million under the HollyFrontier Credit Agreement. At December 31, 2016, we were in compliance with
all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $4.4 million under the HollyFrontier
Credit Agreement.
Indebtedness under the HollyFrontier Credit Agreement bears interest, at our option at either a) an alternate base rate (as defined
in the credit agreement) plus an applicable margin of (ranging from 0.125% - 1.000%), b) LIBOR plus an applicable margin
(ranging from 1.125% to 2.000%), or c) Canadian Dealer Offered Rate plus an applicable margin (ranging from 1.125% to 2.000%)
for Canadian dollar denominated borrowings.
HEP Credit Agreement
HEP has a $1.2 billion senior secured revolving credit facility maturing in November 2018 (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. During the year ended December 31,
2016, HEP received advances totaling $554.0 million and repaid $713.0 million under the HEP Credit Agreement. At December 31,
2016, HEP was in compliance with all of its covenants, had outstanding borrowings of $553.0 million and no outstanding letters
of credit under the HEP Credit Agreement.
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Indebtedness under the HEP Credit Agreement bears interest, at HEP's option, at either a reference rate announced by the
administrative agent plus an applicable margin or at a rate equal to LIBOR plus an applicable margin. In each case, the applicable
margin is based upon the ratio of HEP’s funded debt to earnings before interest, taxes, depreciation and amortization (as defined
in the HEP Credit Agreement). The weighted average interest rates in effect on HEP’s Credit Agreement borrowings were 2.98%
and 2.572% at December 31, 2016 and 2015, respectively.
HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets. 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 recourse to our other assets. Furthermore, our
creditors have no recourse to the assets of HEP and its consolidated subsidiaries.
HollyFrontier Senior Notes
In March 2016 and November 2016, we issued $250 million and $750 million, respectively, in aggregate principal amount of
5.875% senior notes (the “HollyFrontier Senior Notes”) maturing April 2026. The HollyFrontier Senior Notes are unsecured and
unsubordinated obligations of ours and rank equally with all our other existing and future unsecured and unsubordinated
indebtedness.
In June 2015, we redeemed our $150.0 million aggregate principal amount of 6.875% senior notes maturing November 2018 at a
redemption cost of $155.2 million at which time we recognized a $1.4 million early extinguishment loss consisting of a $5.2 million
debt redemption premium, net of an unamortized premium of $3.8 million.
HollyFrontier Financing Obligation
In March 2016, we extinguished a financing obligation at a cost of $39.5 million and recognized an $8.7 million loss on the early
termination. The financing obligation related to a sale and lease-back of certain crude oil tankage that we sold to an affiliate of
Plains in October 2009 for $40.0 million.
HollyFrontier Term Loan
In April 2016, we entered into a $350 million senior unsecured term loan (the “HollyFrontier Term Loan”) maturing in April 2019.
The HollyFrontier Term Loan was fully repaid with proceeds received upon the November 2016 issuance of the HollyFrontier
Senior Notes.
HEP Senior Notes
On January 4, 2017, HEP redeemed its $300 million aggregate principal amount of 6.50% senior notes maturing March 2020 at
a redemption cost of $316.4 million, at which time HEP recognized a $12.2 million early extinguishment loss. HEP funded the
redemption with borrowings under the HEP Credit Agreement.
In July 2016, HEP issued $400 million in aggregate principal amount of 6.0% HEP senior notes maturing in 2024 in a private
placement. HEP used the net proceeds to repay indebtedness under the HEP Credit Agreement.
The 6.0% HEP senior notes (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.
In March 2014, HEP redeemed its $150.0 million aggregate principal amount of 8.25% senior notes maturing March 2018 at a
redemption cost of $156.2 million, at which time HEP recognized a $7.7 million early extinguishment loss consisting of a $6.2
million debt redemption premium and unamortized discount and financing cost of $1.5 million. HEP funded the redemption with
borrowings under the HEP Credit Agreement.
Indebtedness under the HEP Senior Notes is guaranteed by HEP’s wholly-owned subsidiaries. HEP’s creditors have no recourse
to our other assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.
77
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The carrying amounts of long-term debt are as follows:
HollyFrontier 5.875% Senior Notes
Principal
Unamortized discount and debt issuance costs
Financing Obligation
Total HollyFrontier long-term debt
HEP Credit Agreement
HEP 6% Senior Notes
Principal
Unamortized discount and debt issuance costs
HEP 6.5% Senior Notes
Principal
Unamortized discount and debt issuance costs
Total HEP long-term debt
Total long-term debt
The fair values of the senior notes are as follows:
HollyFrontier 5.875% Senior Notes
HEP Senior Notes
December 31,
2016
2015
(In thousands)
$
$
1,000,000
(8,775)
991,225
—
991,225
553,000
400,000
(6,607)
393,393
300,000
(2,481)
297,519
—
—
—
31,288
31,288
712,000
—
—
—
300,000
(3,248)
296,752
1,243,912
1,008,752
$
2,235,137
$
1,040,040
December 31,
2016
2015
(In thousands)
$
$
1,022,500
723,750
$
$
—
295,500
These fair values are based on estimates provided by a third party using market quotes for similar type instruments, a Level 2
input. See Note 4 for additional information on Level 2 inputs.
Principal maturities of long-term debt are as follows:
Years Ending December 31,
(In thousands)
2017
2018
2019
2020
2021
Thereafter
Total
$
$
—
553,000
—
300,000
—
1,400,000
2,253,000
78
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
NOTE 13: 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, forward purchase and sales 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.
Accounting Hedges
We have swap contracts serving as cash flow hedges against price risk on forecasted purchases of natural gas. We also periodically
have forward sales contracts that lock in the prices of future sales of crude oil and refined product and swap contracts serving as
cash flow hedges against price risk on forecasted purchases of WTI crude oil and forecasted sales of refined product. These contracts
have been designated as accounting hedges and are measured 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. 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 and forward sales 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, 2016
Commodity price swaps
Change in fair value
Loss reclassified to earnings due to
settlements
Amortization of discontinued hedges
reclassified to earnings
Total
Year Ended December 31, 2015
Commodity price swaps
Change in fair value
Gain reclassified to earnings due to
settlements
Amortization of discontinued hedges
reclassified to earnings
Total
Year Ended December 31, 2014
Commodity price swaps
Change in fair value
Gain reclassified to earnings due to
settlements
Amortization of discontinued hedges
reclassified to earnings
Total
$
$
$
$
$
$
(17,018)
41,077
1,080
25,139
(3,983)
(49,592)
1,080
(52,495)
Sales and other
revenues
Operating
expenses
Sales and other
revenues
Cost of products
sold
Operating
expenses
Sales and other
revenues
Cost of products
sold
Operating
expenses
107,518
(52,884)
1,080
55,714
79
$
$
$
$
$
$
(In thousands)
(20,293)
(21,864)
(42,157)
Operating
expenses
Sales and other
revenues
Cost of products
sold
Operating
expenses
245,819
(179,700)
(17,607)
48,512
Sales and other
revenues
Cost of products
sold
Operating
expenses
88,326
(37,313)
791
51,804
$
$
$
$
$
$
—
—
(274)
4,376
547
4,649
274
(4,377)
(547)
(4,650)
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
As of December 31, 2016, we have the following notional contract volumes related to outstanding derivative instruments serving
as cash flow hedges against price risk on forecasted transactions (all maturing in 2017):
Derivative instruments
Natural gas price swaps - long
WTI crude oil price swaps - long
Sub-octane gasoline price swaps - short
Forward gasoline and diesel contracts - short
Physical crude contracts - short
Total
Outstanding
Notional
Unit of
Measure
9,600,000 MMBTU
519,000 Barrels
519,000 Barrels
175,000 Barrels
150,000 Barrels
In 2013, we dedesignated certain commodity price swaps (long positions) that previously received hedge accounting treatment.
These contracts now serve as economic hedges against price risk on forecasted natural gas purchases totaling 9,600,000 MMBTU's
to be purchased ratably through 2017. As of December 31, 2016, we have an unrealized loss of $1.1 million classified in accumulated
other comprehensive income that relates to the application of hedge accounting prior to dedesignation that is amortized as a charge
to operating expenses as the contracts mature.
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 purchases of WTI crude oil and forecasted sales of refined product, and to lock in
the basis spread differentials on forecasted purchases of crude oil and natural gas. Also, we have NYMEX futures contracts to lock
in prices on forecasted purchases of inventory. These contracts are measured at fair value with offsetting adjustments (gains/losses)
recorded directly to income.
The following table presents the pre-tax effect on income due to maturities and fair value adjustments of our economic hedges:
Location of Gain (Loss) Recognized in Income
Cost of products sold
Operating expenses
Other, net
Total
Years Ended December 31,
2016
2015
(In thousands)
2014
(6,889)
$
48,082
$
68,509
7,276
(6,520)
(12,003)
—
(185)
—
(6,133)
$
36,079
$
68,324
$
$
As of December 31, 2016, we have the following notional contract volumes related to our outstanding derivative contracts serving
as economic hedges (all maturing in 2017):
Derivative Instrument
Crude price swaps (basis spread) - long
Natural gas price swaps (basis spread) - long
Natural gas price swaps - long
Natural gas price swaps - short
WTI crude oil price swaps - long
WTI crude oil price swaps - short
Sub-octane gasoline price swaps - short
Sub-octane gasoline price swaps - long
NYMEX futures (WTI) - short
Forward gasoline and diesel contracts - long
80
Total
Outstanding
Notional
Unit of
Measure
3,645,000 Barrels
10,308,000 MMBTU
9,600,000 MMBTU
9,600,000 MMBTU
310,000 Barrels
310,000 Barrels
310,000 Barrels
310,000 Barrels
755,000 Barrels
1,225,000 Barrels
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
At December 31, 2016, we had Canadian currency swap contracts that effectively fixed the conversion rate on $1.125 billion
Canadian dollars (the PCLI purchase price) at a USD / CAD exchange rate of 1.33. These swap contracts were settled on February
1, 2017, in connection with the closing of the PCLI acquisition.
Interest Rate Risk Management
HEP uses interest rate swaps to manage its exposure to interest rate risk.
As of December 31, 2016, HEP had two interest rate swap contracts with identical terms that hedge its exposure to the cash flow
risk caused by the effects of LIBOR changes on $150.0 million in credit agreement advances. The swaps 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, 2016, which equaled an effective interest rate of 2.99%. Both of these swap contracts mature in July 2017 and have
been designated as cash flow hedges. To date, there has been no ineffectiveness on these cash flow hedges.
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 hedge accounting:
Year Ended December 31, 2016
Interest rate swaps
Change in fair value
Loss reclassified to earnings due to settlements
Total
Year Ended December 31, 2015
Interest rate swaps
Change in fair value
Loss reclassified to earnings due to settlements
Total
Year Ended December 31, 2014
Interest rate swaps
Change in fair value
Loss reclassified to earnings due to settlements
Total
Unrealized Gain
(Loss)
Recognized in
OCI
Loss Recognized in Earnings Due to
Settlements
Location
(In thousands)
Amount
$
$
$
$
$
$
(607)
508
(99)
(1,864)
2,100
236
(2,104)
2,202
98
Interest expense
Interest expense
Interest expense
$
$
$
$
$
$
(508)
(508)
(2,100)
(2,100)
(2,202)
(2,202)
81
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The following table presents the fair value and balance sheet locations of our outstanding derivative instruments. These amounts
are presented on a gross basis with offsetting balances that reconcile to a net asset or liability position in our consolidated balance
sheets. We present on a net basis to reflect the net settlement of these positions in accordance with provisions of our master netting
arrangements.
Derivatives in Net Asset Position
Derivatives in Net Liability Position
Gross
Liabilities
Offset in
Balance Sheet
Gross Assets
Net Assets
Recognized in
Balance Sheet
Gross
Liabilities
Gross Assets
Offset in
Balance Sheet
(In thousands)
Net
Liabilities
Recognized in
Balance Sheet
December 31, 2016
Derivatives designated as cash flow hedging instruments:
Commodity price swap
contracts
Commodity forward contracts
Interest rate swap contracts
$
$
— $
—
91
91
$
Derivatives not designated as cash flow hedging instruments:
Commodity price swap
contracts
NYMEX futures contracts
Commodity forward contracts
Foreign currency forward
contracts
$
$
4,244
—
5,905
—
10,149
$
$
— $
—
—
— $
(756) $
—
—
—
(756) $
Total net balance
Balance sheet classification:
Prepayment and other
$
$
— $
—
91
91
$
$
$
3,488
—
5,905
—
9,393
9,484
9,484
13,185
2,978
—
16,163
12,903
1,975
5,338
6,519
26,735
$
$
$
$
Accrued liabilities
(431) $
—
—
(431) $
(9,887) $
—
—
—
(9,887) $
$
$
12,754
2,978
—
15,732
3,016
1,975
5,338
6,519
16,848
32,580
32,580
Derivatives in Net Asset Position
Derivatives in Net Liability Position
Gross
Liabilities
Offset in
Balance Sheet
Gross Assets
Net Assets
Recognized in
Balance Sheet
Gross
Liabilities
Gross Assets
Offset in
Balance Sheet
(In thousands)
Net
Liabilities
Recognized in
Balance Sheet
December 31, 2015
Derivatives designated as cash flow hedging instruments:
Commodity price swap
contracts
Interest rate swap contracts
$
$
— $
304
304
$
Derivatives not designated as cash flow hedging instruments:
Commodity price swap
contracts
NYMEX futures contracts
$
$
— $
3,469
3,469
$
Total net balance
Balance sheet classification:
Prepayment and other
Intangibles and other
— $
304
304
$
— $
3,469
3,469
$
3,773
3,469
304
3,773
38,755
114
38,869
60,196
—
60,196
$
$
$
$
— $
—
— $
(37,118) $
—
(37,118) $
Accrued liabilities
Other long-term liabilities
$
$
$
$
38,755
114
38,869
23,078
—
23,078
61,947
36,976
24,971
61,947
— $
—
— $
— $
—
— $
$
$
$
82
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
At December 31, 2016, we had a pre-tax net unrealized loss of $15.8 million classified in accumulated other comprehensive income
that relates to all accounting hedges having contractual maturities through 2017. Assuming commodity prices and interest rates
remain unchanged, this unrealized loss will be effectively transferred from accumulated other comprehensive income into the
statement of income as the hedging instruments contractually mature over the next twelve-month period.
NOTE 14: Income Taxes
The provision for income taxes is comprised of the following:
Current
Federal
State
Deferred
Federal
State
2016
Years Ended December 31,
2015
(In thousands)
2014
$
$
(71,878) $
(7,304)
480,446
71,750
100,208
(1,615)
19,411
$
(127,714)
(18,422)
406,060
$
$
294,509
40,325
(168,756)
(24,906)
141,172
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
Goodwill
Other
2016
Years Ended December 31,
2015
(In thousands)
2014
$
$
(60,037) $
(14,056)
4,170
(26,903)
119,722
(3,485)
19,411
$
422,999
40,385
(35,200)
(24,155)
—
2,031
406,060
$
$
163,625
13,641
(20,998)
(17,431)
—
2,335
141,172
83
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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, 2016 and 2015 are as follows:
Assets
December 31, 2016
Liabilities
(In thousands)
Total
Deferred income taxes
Properties, plants and equipment (due primarily to tax in excess of
book depreciation)
Accrued employee benefits
Accrued post-retirement benefits
Accrued environmental costs
Hedging instruments
Inventory differences
Deferred turnaround costs
Net operating loss and tax credit carryforwards
Investment in HEP
Other
Total
Deferred income taxes
Properties, plants and equipment (due primarily to tax in excess of
book depreciation)
Accrued employee benefits
Accrued post-retirement benefits
Accrued environmental costs
Hedging instruments
Inventory differences
Deferred turnaround costs
Net operating loss and tax credit carryforwards
Investment in HEP
Other
Total
$
— $
(618,053) $
21,355
10,024
41,152
7,396
—
—
23,203
—
14,119
117,249
—
—
—
—
(8,341)
(83,993)
—
(27,276)
—
$
(737,663) $
(618,053)
21,355
10,024
41,152
7,396
(8,341)
(83,993)
23,203
(27,276)
14,119
(620,414)
Assets
December 31, 2015
Liabilities
(In thousands)
Total
— $
22,355
11,518
42,517
21,815
175,614
—
8,033
—
—
281,852
$
(648,542) $
—
—
—
—
—
(104,944)
—
(23,429)
(2,843)
(779,758) $
(648,542)
22,355
11,518
42,517
21,815
175,614
(104,944)
8,033
(23,429)
(2,843)
(497,906)
$
$
$
At December 31, 2016, we had a U.S. federal income tax net operating loss of $199.0 million that is scheduled to be carried back
to 2014. As a result of this net operating loss, we expect to pay alternative minimum tax for 2016 and to generate a deferred credit.
We generated a $11.0 million state operating loss, which can be carried back in some states, but is generally carried forward for
5 to 20 years. We also generated an Oklahoma income tax credit of $3.0 million that can be carried forward indefinitely, and a
Kansas income tax credit that can be carried forward for 16 tax years.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
84
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Balance at January 1
Additions based on tax positions related to the current year
Settlements
Balance at December 31
Years Ended December 31,
2016
2015
(In thousands)
2014
$
$
— $
— $
22,137
—
—
—
22,137
$
— $
9,006
—
(9,006)
—
At December 31, 2016 there were $22.1 million of unrecognized tax benefits that, if recognized, would affect our effective tax
rate. We had no unrecognized benefits at December 31, 2015 or 2014. 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.
The 2016 addition to unrecognized tax benefits relates to claims filed with the IRS on the federal income tax treatment of refundable
biodiesel/ethanol blending tax credits for certain prior years. The issues related to the claims are complex and uncertain, and we
cannot conclude that it is more likely than not that we will sustain the claims. Therefore, no tax benefit has been recognized for
the filed claims. The Company believes it is reasonably possible that the total amounts of unrecognized tax benefits will significantly
increase within 12 months of the reporting date based on additional filings.
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 are subject to U.S. federal income tax, Oklahoma, Kansas, New Mexico, Iowa, Arizona, Utah, Colorado and Nebraska income
tax and to income tax of multiple other state jurisdictions. We have substantially concluded all state and local income tax matters
for tax years through 2011. Other than the federal claim noted above, we have materially concluded all U.S. federal income tax
matters for tax years through December 31, 2013.
NOTE 15: Stockholders' Equity
Shares of our common stock outstanding and activity for the years ended December 31, 2016, 2015 and 2014 are presented below:
Common shares outstanding at January 1
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
Years Ended December 31,
2015
2014
2016
180,234,388
196,086,090
198,830,351
870,378
76,404
40,294
(16,795)
(3,859,403)
177,345,266
447,534
136,896
43,774
(51,332)
(16,428,574)
180,234,388
376,622
416,111
77,430
(76,107)
(3,538,317)
196,086,090
(1) Includes 147,922, 151,967 and 279,680 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, as well as other stock repurchases
under separate authority from our Board of Directors.
In May 2015, our Board of Directors approved a $1 billion share repurchase program, which replaced all existing share repurchase
programs, authorizing 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 and corporate, regulatory and other relevant considerations.
This program may be discontinued at any time by the Board of Directors. As of December 31, 2016, we had remaining authorization
to repurchase up to $178.8 million under this stock repurchase program. In addition, we are authorized by our Board of Directors
to repurchase shares in an amount sufficient to offset shares issued under our compensation programs.
85
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
During the years ended December 31, 2016, 2015 and 2014, we withheld shares of our common stock from certain employees in
the amounts of $4.7 million, $6.2 million and $11.4 million, respectively. These withholdings were made under the terms of
restricted stock and performance share unit agreements upon vesting, at which time, we concurrently made cash payments to fund
payroll and income taxes on behalf of officers and employees who elected to have shares withheld from vested amounts to pay
such taxes.
NOTE 16: Other Comprehensive Income (Loss)
The components and allocated tax effects of other comprehensive income (loss) are as follows:
Year Ended December 31, 2016
Net unrealized gain on marketable securities
Net unrealized gain on hedging instruments
Net change in other post-retirement benefit obligations
Other comprehensive income
Less other comprehensive loss attributable to noncontrolling interest
Other comprehensive gain attributable to HollyFrontier stockholders
Year Ended December 31, 2015
Net unrealized gain on marketable securities
Net unrealized loss on hedging instruments
Net change in other post-retirement benefit obligations
Other comprehensive loss
Less other comprehensive income attributable to noncontrolling interest
Other comprehensive loss attributable to HollyFrontier stockholders
Year Ended December 31, 2014
Net unrealized loss on marketable securities
Net unrealized gain on hedging instruments
Net change in other post-retirement benefit obligations
Other comprehensive income
Less other comprehensive income attributable to noncontrolling interest
Other comprehensive income attributable to HollyFrontier stockholders
Before-Tax
Tax Expense
(Benefit)
(In thousands)
After-Tax
$
$
$
$
$
$
104
25,040
(1,113)
24,031
(58)
24,089
$
$
$
38
(52,259)
79
(52,142)
144
(52,286) $
40
9,713
(431)
9,322
—
9,322
$
$
$
14
(20,282)
31
(20,237)
—
(20,237) $
(157) $
(62) $
55,812
(11,425)
44,230
60
44,170
$
21,583
(4,423)
17,098
—
17,098
$
64
15,327
(682)
14,709
(58)
14,767
24
(31,977)
48
(31,905)
144
(32,049)
(95)
34,229
(7,002)
27,132
60
27,072
86
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
The following table presents the income statement line item effects for reclassifications out of accumulated other comprehensive
income (“AOCI”):
AOCI Component
Gain (Loss) Reclassified From AOCI
Income Statement Line Item
Marketable securities
$
Years Ended December 31,
2016
2015
(In thousands)
2014
(23) $
—
(23)
(9)
(14)
(51) $
42
(9)
(3)
(6)
4
Interest income
— Gain on sale of assets
4
2
2 Net of tax
Income tax expense (benefit)
Hedging instruments:
Commodity price swaps
Interest rate swaps
Other post-retirement benefit
obligations:
Post-retirement healthcare
obligation
Retirement restoration plan
(20,293)
—
(21,864)
(508)
(42,665)
(16,387)
(26,278)
320
(25,958)
130
2,989
363
3,482
1,348
2,134
(15)
(6)
(9)
245,819
(179,700)
(17,607)
(2,100)
46,412
18,454
27,958
1,273
29,231
271
2,681
347
3,299
1,277
2,022
(20)
(8)
(12)
88,326 Sales and other revenues
(37,313) Cost of products sold
791 Operating expenses
Interest expense
(2,202)
49,602
19,712
29,890 Net of tax
1,335 Noncontrolling interest
31,225 Net of tax and noncontrolling interest
Income tax expense (benefit)
482 Cost of products sold
3,366 Operating expenses
448 General and administrative expenses
4,296
1,663
2,633 Net of tax
Income tax expense
(920) General and administrative expenses
(356)
(564) Net of tax
Income tax benefit
Total reclassifications for the period
$
(23,847) $
31,235
$
33,296
Accumulated other comprehensive income (loss) in the equity section of our consolidated balance sheets includes:
Years Ended December 31,
2016
2015
Unrealized gain on post-retirement benefit obligations
Unrealized gain (loss) on marketable securities
Unrealized loss on hedging instruments, net of noncontrolling interest
Accumulated other comprehensive income (loss)
$
$
$
(In thousands)
20,055
3
(9,446)
10,612
$
20,737
(61)
(24,831)
(4,155)
NOTE 17: Retirement Plans
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, 2016.
87
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
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, 2016 and 2015:
Change in plans' benefit obligation
Post-retirement plans' benefit obligation - beginning of year
Service cost
Interest cost
Participant contributions
Amendments
Benefits paid
Actuarial loss (gain)
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 income (loss)
Cumulative actuarial loss
Prior service credit
Total
Years Ended December 31,
2016
2015
(In thousands)
21,201
1,294
787
244
21
(2,171)
(2,384)
18,992
$
$
— $
1,927
244
(2,171)
— $
23,633
1,694
819
593
—
(2,260)
(3,278)
21,201
—
1,667
593
(2,260)
—
(18,992) $
(21,201)
(18,992) $
(21,201)
771
32,434
33,205
$
$
(1,613)
35,937
34,324
$
$
$
$
$
$
$
$
Benefit payments, which reflect expected future service, are expected to be paid as follows: $1.8 million in 2017; $1.7 million in
2018; $1.6 million in 2019; $1.6 million in 2020; $1.7 million in 2021; and $8.3 million in 2022 through 2026.
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,
2016
2015
3.75%
7.00%
5.00%
2030
3.90%
8.00%
5.00%
2041
88
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Net periodic post-retirement credit consisted of the following components:
Service cost – benefit earned during the year
Interest cost on projected benefit obligations
Amortization of prior service credit
Amortization of net loss
Net periodic post-retirement credit
2016
Years Ended December 31,
2015
(In thousands)
2014
$
$
$
1,294
787
(3,482)
—
(1,401) $
$
1,694
819
(3,482)
183
(786) $
895
638
(4,296)
—
(2,763)
Prior service credits are amortized over the average remaining effective period to obtain full benefit eligibility for participants.
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:
Discount rate
Current health care trend rate
Ultimate health care trend rate
Year rate reaches ultimate trend rate
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
Years Ended December 31,
2015
2014
2016
3.90%
8.00%
5.00%
2041
3.60%
8.00%
5.00%
2042
4.25%
8.00%
5.00%
2045
1% Point
Increase
1% Point
Decrease
$
$
$
(In thousands)
187
56
1,286
$
$
$
(156)
(49)
(1,118)
Pension Plan
We had a program that provided transition benefit payments to certain employees that participated in a previously terminated
defined benefit plan. The program extended through 2014 and provided payments subsequent to year-end provided the employee
was employed by us on the last day of each year. The payments were based on each employee's years of service and eligible salary.
Transition benefit costs under this program were $10.8 million for the year ended December 31, 2014. In March 2015, we paid
all remaining amounts owed to plan participants of $11.0 million.
Retirement Restoration Plan
We have 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. We expensed $0.1 million, $0.1 million and $1.2 million for the years ended December 31, 2016, 2015 and 2014,
respectively, in connection with this plan. The accrued liability reflected in the consolidated balance sheets was $2.7 million and
$2.8 million at December 31, 2016 and 2015, respectively. As of December 31, 2016, the projected benefit obligation under this
plan was $2.7 million. Annual benefit payments of $0.2 million are expected to be paid through 2026, which reflect expected future
service.
Defined Contribution Plan
We have a defined contribution “401(k)” plan that covers substantially all employees. Our contributions are based on an employee's
eligible compensation and years of service. We also partially match the employee's contributions. We expensed $17.5 million,
$17.2 million and $16.1 million for the years ended December 31, 2016, 2015 and 2014, respectively, in connection with this plan.
89
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
NOTE 18: Lease Commitments
We lease certain office and storage facilities, rail cars and other equipment under long-term operating leases, most of which contain
renewal options. At December 31, 2016, the minimum future rental commitments under operating leases having non-cancellable
lease terms in excess of one year are as follows:
2017
2018
2019
2020
2021
Thereafter
Total
(In thousands)
75,156
67,463
61,893
60,035
56,684
172,627
493,858
$
$
Rental expense charged to operations was $93.2 million, $107.3 million and $89.8 million for the years ended December 31, 2016,
2015 and 2014, respectively. For the years ended December 31, 2016, 2015 and 2014, rental expense included $8.5 million, $8.9
million and $8.0 million, respectively, in costs attributable to the HEP operations.
NOTE 19: 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 2017 through 2030.
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 2017 through 2033. At December 31, 2016, the minimum
future transportation and storage fees under transportation agreements having terms in excess of one year are as follows:
2017
2018
2019
2020
2021
Thereafter
Total
$
(In thousands)
136,052
135,048
123,105
110,929
98,834
894,033
$
1,498,001
Transportation and storage costs incurred under these agreements totaled $135.1 million, $137.7 million and $118.0 million for
the years ended December 31, 2016, 2015 and 2014, respectively. These amounts do not include contractual commitments under
our long-term transportation agreements with HEP, as all transactions with HEP are eliminated in these consolidated financial
statements.
90
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
NOTE 20: 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 HFC
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. HFC Asphalt operates various asphalt terminals in Arizona, New Mexico and Oklahoma.
The HEP segment includes all of the operations of HEP, which owns and operates logistics and refinery assets consisting of
petroleum product and crude oil pipelines, terminals, tankage, loading rack facilities and processing units in the Mid-Continent,
Southwest and Rocky Mountain regions of the United States. The HEP segment also includes a 75% ownership interest in UNEV
(a consolidated subsidiary of HEP), a 50% ownership interest in each of the Frontier Pipeline, Osage Pipeline and the Cheyenne
Pipeline and a 25% ownership 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. Due to certain basis differences, 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).
Refining (1,2)
HEP (2)
Corporate
and Other
Consolidations
and Eliminations
Consolidated
Total
Year Ended December 31, 2016
Sales and other revenues
Depreciation and amortization
Income (loss) from operations
Earnings of equity method investments
Capital expenditures
Total assets
Year Ended December 31, 2015
Sales and other revenues
Depreciation and amortization
Income (loss) from operations
Earnings (loss) of equity method investments
Capital expenditures
Total assets
Year Ended December 31, 2014
Sales and other revenues
Depreciation and amortization
Income (loss) from operations
Earnings of equity method investments
Capital expenditures
Total assets
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
402,043
$
10,467,190
68,811
$
282,321
196,716
(163,624) $
14,213
— $
$
107,595
$ 1,920,487
363,115
6,513,806
13,171,183
273,345
1,190,578
469,011
6,597,355
358,875
$
61,690
$
179,075
$
4,803
— $
$
193,121
$ 1,812,279
19,706,225
293,508
492,853
346,605
6,782,091
332,626
$
60,911
$
154,706
$
2,987
— $
$
198,686
$ 1,617,133
(In thousands)
$
168
$
12,723
(130,565) $
— $
$
$
9,080
1,306,169
$
663
11,944
$
(123,004) $
(8,541) $
$
14,023
$
289,225
$
2,103
$
9,790
(129,874) $
(4,994) $
$
19,530
$
1,150,865
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(333,701) $
(828) $
(2,414) $
— $
— $
(304,801) $
10,535,700
363,027
(99,887)
14,213
479,790
9,435,661
(292,801) $
(828) $
(2,296) $
— $
— $
(310,560) $
13,237,920
346,151
1,244,353
(3,738)
676,155
8,388,299
(276,627) $
(828) $
(2,151) $
— $
— $
(320,042) $
19,764,327
363,381
515,534
(2,007)
564,821
9,230,047
(1) For the year ended December 31, 2016, we recorded goodwill and long-lived asset impairment charges of $309.3 million and
$344.8 million, respectively, that relate to our Cheyenne Refinery, which is included in our Refining segment.
91
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
(2) HEP acquired the crude oil tanks at our Tulsa Refineries in March 2016 and acquired a newly constructed crude unit, FCCU
and polymerization unit at our Woods Cross Refinery in October 2016. As a result, we have recast our 2015 and 2014 HEP segment
information to include these assets and related capital expenditures and certain operating expenses that were previously presented
under the Refining segment. Additionally, prior year capital expenditures related to these assets have been recast as if they were
incurred by HEP versus HFC in the statement of cash flows.
HEP segment revenues from external customers were $68.9 million, $66.7 million and $57.3 million for the years ended
December 31, 2016, 2015 and 2014, respectively.
NOTE 21: Additional Financial Information
Borrowings pursuant to the HollyFrontier Credit Agreement are recourse to HollyFrontier, but not HEP. Furthermore, borrowings
under the HEP Credit Agreement are recourse to HEP, but not to the assets of HFC with the exception of HEP Logistics Holdings,
L.P., HEP’s general partner. Other than its investment in HEP, the assets of the general partner are insignificant.
The following condensed financial information is provided for HollyFrontier Corporation (on a standalone basis, before
consolidation of HEP), and for HEP and its consolidated subsidiaries (on a standalone basis, exclusive of HFC). Due to certain
basis differences, our reported amounts for HEP may not agree to amounts reported in HEP’s periodic public filings.
Condensed Consolidating Balance Sheet
December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents
Marketable securities
Accounts receivable, net
Inventories
Income taxes receivable
Prepayments and other
Total current assets
Properties, plants and equipment, net
Intangibles and other assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
Accrued 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
HollyFrontier
Corp. Before
Consolidation
of HEP
HEP Segment
Consolidations and
Eliminations
Consolidated
(In thousands)
$
706,922
$
3,657
$
424,148
487,693
1,134,274
68,371
37,379
2,858,787
2,874,041
2,077,683
—
50,408
1,402
—
1,486
56,953
1,365,568
497,966
— $
—
(58,902)
—
—
(5,829)
(64,731)
(231,161)
555
$
$
7,810,511
$
1,920,487
$
(295,337) $
967,347
$
26,942
$
(58,902) $
115,878
1,083,225
991,225
208,603
619,905
132,515
136,435
4,638,603
—
37,793
64,735
1,243,912
—
509
62,971
—
454,803
93,557
(5,829)
(64,731)
—
(208,603)
—
(590)
(136,435)
(412,012)
527,034
$
7,810,511
$
1,920,487
$
(295,337) $
92
710,579
424,148
479,199
1,135,676
68,371
33,036
2,851,009
4,008,448
2,576,204
9,435,661
935,387
147,842
1,083,229
2,235,137
—
620,414
194,896
—
4,681,394
620,591
9,435,661
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Balance Sheet
December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents
Marketable securities
Accounts receivable, net
Inventories
Prepayments and other
Total current assets
Properties, plants and equipment, net
Intangibles and other assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
Income tax payable
Accrued 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
HollyFrontier
Corp. Before
Consolidation
of HEP
HEP Segment
Consolidations and
Eliminations
Consolidated
(In thousands)
$
51,520
$
15,013
$
144,019
355,020
839,897
48,288
1,438,744
3,027,614
2,410,879
—
41,075
1,972
3,082
61,142
1,333,563
417,574
— $
—
(44,117)
—
(7,704)
(51,821)
(245,515)
(3,881)
$
$
6,877,237
$
1,812,279
$
(301,217) $
738,024
$
22,583
$
(44,117) $
8,142
117,346
863,512
31,288
220,998
497,475
125,614
129,961
5,008,389
—
—
26,341
48,924
1,008,752
—
431
59,376
—
600,367
94,429
—
(7,704)
(51,821)
—
(220,998)
—
(5,025)
(129,961)
(355,341)
461,929
$
6,877,237
$
1,812,279
$
(301,217) $
66,533
144,019
351,978
841,869
43,666
1,448,065
4,115,662
2,824,572
8,388,299
716,490
8,142
135,983
860,615
1,040,040
—
497,906
179,965
—
5,253,415
556,358
8,388,299
93
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HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
HollyFrontier
Corp. Before
Consolidation
of HEP
HEP Segment
Consolidations and
Eliminations
Consolidated
$
10,467,358
$
(In thousands)
402,043
$
(333,701) $
10,535,700
9,062,757
(291,938)
928,483
113,117
308,569
654,084
10,775,072
(307,714)
100,322
(8,355)
(8,718)
(8,118)
75,131
(232,583)
19,126
(251,709)
(34)
(251,675) $
—
—
123,985
12,531
68,811
—
205,327
196,716
14,213
(52,112)
—
677
(37,222)
159,494
285
159,209
10,006
149,203
(236,908) $
149,161
$
$
(296,830)
—
(33,629)
(14,353)
—
(344,812)
11,111
(100,322)
(9,234)
—
—
(109,556)
(98,445)
—
(98,445)
59,536
(157,981) $
8,765,927
(291,938)
1,018,839
125,648
363,027
654,084
10,635,587
(99,887)
14,213
(69,701)
(8,718)
(7,441)
(71,647)
(171,534)
19,411
(190,945)
69,508
(260,453)
(157,939) $
(245,686)
Condensed Consolidating Statement of Income and
Comprehensive Income
Year Ended December 31, 2016
Sales and other revenues
Operating costs and expenses:
Cost of products sold
Lower of cost or market valuation inventory adjustment
Operating expenses
General and administrative
Depreciation and amortization
Goodwill and asset impairment
Total operating costs and expenses
Income (loss) from operations
Other income (expense):
Earnings of equity method investments
Interest income (expense)
Loss on early extinguishment of debt
Other, net
Income (loss) before income taxes
Income tax provision
Net income (loss)
Less net income attributable to noncontrolling interest
Net income (loss) attributable to HollyFrontier stockholders
Comprehensive income (loss) attributable to HollyFrontier
stockholders
$
$
94
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Statement of Income and
Comprehensive Income
Year Ended December 31, 2015
Sales and other revenues
Operating costs and expenses:
Cost of products sold
Lower of cost or market inventory valuation adjustment
Operating expenses
General and administrative
Depreciation and amortization
Total operating costs and expenses
Income from operations
Other income (expense):
Earnings of equity method investments
Interest income (expense)
Loss on early extinguishment of debt
Other, net
Income before income taxes
Income tax provision
Net income
HollyFrontier
Corp. Before
Consolidation
of HEP
HEP Segment
Consolidations and
Eliminations
Consolidated
$
13,171,846
$
(In thousands)
358,875
$
(292,801) $
13,237,920
10,525,610
226,979
958,103
108,290
298,779
12,117,761
1,054,085
78,969
6,098
(1,370)
8,916
92,613
1,146,698
405,832
740,866
—
—
105,554
12,556
61,690
179,800
179,075
4,803
(36,892)
—
486
(31,603)
147,472
228
147,244
11,120
136,124
136,217
(286,392)
—
(3,284)
—
(14,318)
(303,994)
11,193
(87,510)
(9,285)
—
—
(96,795)
(85,602)
—
(85,602)
51,317
$
$
(136,919) $
(137,012) $
10,239,218
226,979
1,060,373
120,846
346,151
11,993,567
1,244,353
(3,738)
(40,079)
(1,370)
9,402
(35,785)
1,208,568
406,060
802,508
62,407
740,101
708,052
Less net income attributable to noncontrolling interest
Net income attributable to HollyFrontier stockholders
Comprehensive income attributable to HollyFrontier stockholders
$
$
(30)
740,896
708,847
$
$
95
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Statement of Income and
Comprehensive Income
Year Ended December 31, 2014
Sales and other revenues
Operating costs and expenses:
Cost of products sold
Lower of cost or market inventory valuation adjustment
Operating expenses
General and administrative
Depreciation and amortization
Total operating costs and expenses
Income from operations
Other income (expense):
Earnings of equity method investments
Interest expense
Loss on early extinguishment of debt
Other, net
Income before income taxes
Income tax provision
Net income
HollyFrontier
Corp. Before
Consolidation
of HEP
HEP Segment
Consolidations and
Eliminations
Consolidated
$
19,708,328
$
(In thousands)
332,626
$
(276,627) $
19,764,327
17,500,601
397,478
1,040,187
103,785
316,786
19,358,837
349,491
65,375
6,221
—
866
72,462
421,953
140,937
281,016
—
—
106,185
10,824
60,911
177,920
154,706
2,987
(36,098)
(7,677)
—
(40,788)
113,918
235
113,683
8,288
105,395
105,434
(272,216)
—
(1,432)
—
(14,316)
(287,964)
11,337
(70,369)
(9,339)
—
—
(79,708)
(68,371)
—
(68,371)
36,773
$
$
(105,144) $
(105,183) $
17,228,385
397,478
1,144,940
114,609
363,381
19,248,793
515,534
(2,007)
(39,216)
(7,677)
866
(48,034)
467,500
141,172
326,328
45,036
281,292
308,364
Less net income attributable to noncontrolling interest
Net income attributable to HollyFrontier stockholders
Comprehensive income attributable to HollyFrontier stockholders
$
$
(25)
281,041
308,113
$
$
96
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2016
HollyFrontier
Corp. Before
Consolidation
of HEP
Cash flows from operating activities
$
460,918
$
HEP Segment
Consolidations and
Eliminations
Consolidated
(In thousands)
242,761
$
(101,408) $
602,271
Cash flow from investing activities
Additions to properties, plants and equipment
Additions to properties, plants and equipment – HEP
Purchase of equity method investment
Proceeds from sale of assets
Purchases of marketable securities
Sales and maturities of marketable securities
Cash flows from financing activities
Net repayments under credit agreement – HEP
Net proceeds from issuance of senior notes - HFC
Net proceeds from issuance of senior notes - HEP
Net proceeds from issuance of term loan
Repayment of term loan
Proceeds from issuance of common units
Purchase of treasury stock
Dividends
Distributions to noncontrolling interest
Repayment of financing obligation
Distribution from HEP
Contribution from general partner
Other, net
Cash and cash equivalents
Increase (decrease) for the period
Beginning of period
End of period
(372,195)
—
—
422
(546,632)
266,603
(651,802)
—
992,550
—
350,000
(350,000)
—
(133,430)
(234,004)
—
—
278,000
(53,839)
(2,991)
846,286
—
(103,823)
(42,627)
427
—
—
—
(3,772)
—
—
—
—
(146,023)
(3,772)
(159,000)
—
394,000
—
—
125,870
—
—
(197,787)
(39,500)
(278,000)
53,839
(7,516)
(108,094)
—
—
—
—
—
—
—
—
105,180
—
—
—
—
105,180
655,402
51,520
706,922
$
(11,356)
15,013
3,657
$
$
—
—
— $
(372,195)
(107,595)
(42,627)
849
(546,632)
266,603
(801,597)
(159,000)
992,550
394,000
350,000
(350,000)
125,870
(133,430)
(234,004)
(92,607)
(39,500)
—
—
(10,507)
843,372
644,046
66,533
710,579
97
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2015
HollyFrontier
Corp. Before
Consolidation
of HEP
HEP Segment
Consolidations and
Eliminations
Consolidated
(In thousands)
Cash flows from operating activities
$
839,106
$
230,940
$
(90,420) $
979,626
Cash flows from investing activities:
Additions to properties, plants and equipment
Additions to properties, plants and equipment – HEP
Purchase of equity method investment
Proceeds from sale of assets
Purchases of marketable securities
Sales and maturities of marketable securities
Cash flows from financing activities:
Net borrowings under credit agreement – HEP
Redemption of senior notes - HFC
Purchase of treasury stock
Dividends
Distributions to noncontrolling interest
Distribution from HEP
Contribution from general partner
Other, net
Cash and cash equivalents
Increase (decrease) for the period:
Beginning of period
End of period
(483,034)
—
—
17,985
(509,338)
839,513
(134,874)
—
(155,156)
(742,823)
(246,908)
—
62,000
(128,476)
(6,504)
(1,217,867)
(513,635)
565,155
—
(193,121)
(55,032)
1,279
—
—
(246,874)
141,000
—
—
—
(173,688)
(62,000)
128,476
(5,671)
28,117
12,183
2,830
$
51,520
$
15,013
$
—
—
—
—
—
—
—
—
—
—
—
90,420
—
—
—
90,420
—
—
— $
(483,034)
(193,121)
(55,032)
19,264
(509,338)
839,513
(381,748)
141,000
(155,156)
(742,823)
(246,908)
(83,268)
—
—
(12,175)
(1,099,330)
(501,452)
567,985
66,533
98
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2014
HollyFrontier
Corp. Before
Consolidation
of HEP
HEP Segment
Consolidations and
Eliminations
Consolidated
(In thousands)
Cash flows from operating activities
$
653,570
$
185,519
$
(80,493) $
758,596
Cash flows from investing activities:
Additions to properties, plants and equipment
Additions to properties, plants and equipment – HEP
Proceeds from sale of assets
Purchases of marketable securities
Sales and maturities of marketable securities
Other, net
Cash flows from financing activities:
Net borrowings under credit agreement – HEP
Redemptions of senior notes
Purchase of treasury stock
Contribution from general partner
Dividends
Distributions to noncontrolling interest
Excess tax benefit from equity-based compensation
Other, net
Cash and cash equivalents
Decrease for the period:
Beginning of period
End of period
(366,135)
—
16,633
(1,025,602)
1,276,447
5,021
(93,636)
—
—
(158,847)
(120,111)
(647,197)
—
2,040
(4,415)
(928,530)
(368,596)
933,751
$
565,155
$
—
(198,686)
—
—
—
—
(198,686)
208,000
(156,188)
—
120,111
—
(158,695)
—
(3,583)
9,645
(3,522)
6,352
2,830
$
—
—
—
—
—
—
—
—
—
—
—
—
80,493
—
—
80,493
—
—
— $
(366,135)
(198,686)
16,633
(1,025,602)
1,276,447
5,021
(292,322)
208,000
(156,188)
(158,847)
—
(647,197)
(78,202)
2,040
(7,998)
(838,392)
(372,118)
940,103
567,985
99
Table of Contents
HOLLYFRONTIER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Continued
NOTE 22: Significant Customers
All revenues are domestic revenues, except for sales of refined products for export into Mexico. We have two significant customers
(Shell Oil and Sinclair), each of which has historically accounted for 10% or more of our annual Refining segment revenues. Shell
Oil accounted for $1,048.2 million (10%), $1,252.6 million (9%) and $2,097.4 million (11%) for the years ended December 31,
2016, 2015 and 2014, respectively, and Sinclair accounted for $927.0 million (9%), $1,104.9 million (8%) and $2,018.8 million
(10%) of our revenues for the years ended December 31, 2016, 2015 and 2014, respectively. Our export sales were less than 3%
of our revenues for the years ended December 31, 2016, 2015 and 2014.
NOTE 23: Quarterly Information (Unaudited)
Year Ended December 31, 2016
Sales and other revenues
Operating costs and expenses
Income (loss) from operations (1,2)
Income (loss) before income taxes
Net income (loss) attributable to
HollyFrontier stockholders
Net income (loss) per share attributable to
HollyFrontier stockholders - basic
Net income (loss) 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, 2015
Sales and other revenues
Operating costs and expenses
Income (loss) from operations (3)
Income (loss) before income taxes
Net income (loss) attributable to
HollyFrontier stockholders
Net income (loss) per share attributable to
HollyFrontier stockholders - basic
Net income (loss) per share attributable to
HollyFrontier stockholders - diluted
Dividends per common share
Average number of shares of common
stock outstanding:
Basic
Diluted
First
Quarter
$ 2,018,724
$ 1,935,126
83,598
$
65,698
$
Second
Quarter
Third
Quarter
(In thousands, except per share data)
Fourth
Quarter
Year
$ 2,714,638
$ 3,135,180
$
$
(420,542) $
(430,515) $
$ 2,847,270
$ 2,722,505
124,765
109,867
$
$
$
$
21,253
0.12
0.12
0.33
$
$
$
$
(409,368) $
74,497
(2.33) $
(2.33) $
$
0.33
0.42
0.42
0.33
$ 2,955,068
$ 2,842,776
112,292
$
83,416
$
$ 10,535,700
$ 10,635,587
(99,887)
$
(171,534)
$
$
$
$
$
53,165
0.30
0.30
0.33
$
$
$
$
(260,453)
(1.48)
(1.48)
1.32
176,737
176,784
175,865
175,865
175,871
175,993
175,936
176,137
176,101
176,101
$ 3,006,626
$ 2,618,004
388,622
$
372,389
$
$ 3,701,912
$ 3,112,080
589,832
$
580,177
$
$ 3,585,823
$ 3,263,218
322,605
$
320,673
$
$ 2,943,559
$ 3,000,265
$
$
$ 13,237,920
$ 11,993,567
(56,706) $ 1,244,353
(64,671) $ 1,208,568
$
$
$
$
226,876
1.16
1.16
0.32
$
$
$
$
360,824
1.88
1.88
0.33
$
$
$
$
196,322
1.05
1.04
0.33
$
$
$
$
(43,921) $
740,101
(0.24) $
(0.24) $
$
0.33
3.91
3.90
1.31
195,069
195,121
191,355
191,454
187,208
187,344
181,460
181,460
188,731
188,940
(1) For 2016, income from operations reflects non-cash lower of cost or market inventory valuation reductions of $56.1 million and $138.5
million for the first and second quarters, respectively, and a charge of $0.3 million for the third quarter and a reduction of $97.7 million for the
fourth quarter.
(2) For 2016, income from operations reflects non-cash goodwill and long-lived asset impairment charges of $654.1 million in the second quarter.
(3) For 2015, income from operations reflects non-cash lower of cost or market inventory valuation reductions of $6.5 million and $135.5 million
for the first and second quarters, respectively, and increases of $225.5 million and $143.6 million for the third and fourth quarters, respectively.
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, 2016.
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 2016 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 11, 2017 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 11, 2017 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 11, 2017 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 11, 2017 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 11, 2017 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, 2016 and 2015
Consolidated Statements of Income for the years ended
December 31, 2016, 2015 and 2014
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the years ended
December 31, 2016, 2015 and 2014
Consolidated Statements of Equity for the years ended
December 31, 2016, 2015 and 2014
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 104 to 108 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 22, 2017
HOLLYFRONTIER CORPORATION
(Registrant)
/s/ George J. Damiris
George J. Damiris
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
Michael C. Jennings
/s/ George J. Damiris
George J. Damiris
/s/ Douglas S. Aron
Douglas S. Aron
/s/ J.W. Gann, Jr.
J.W. Gann, Jr.
/s/ Douglas Y. Bech
Douglas Y. Bech
/s/ Leldon Echols
Leldon Echols
/s/ R. Kevin Hardage
R. Kevin Hardage
/s/ Robert J. Kostelnik
Robert J. Kostelnik
/s/ James H. Lee
James H. Lee
/s/ Franklin Myers
Franklin Myers
/s/ Michael E. Rose
Michael E. Rose
Chairman
February 22, 2017
February 22, 2017
February 22, 2017
February 22, 2017
February 22, 2017
February 22, 2017
February 22, 2017
February 22, 2017
February 22, 2017
February 22, 2017
February 22, 2017
Chief Executive Officer, President
and Director
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Vice President, Controller and
Chief Accounting Officer
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
103
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
10.1
10.2
10.3
10.4
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).
Share Purchase Agreement, dated October 29, 2016, by and between Suncor Energy Inc. and 9952110 Canada Inc.
(incorporated by reference to Exhibit 2.1 of Registrant's Current Report on Form 8-K filed October 31, 2016, 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 February 20, 2014, File No. 1-03876).
Indenture, dated July 19, 2016, among Holly Energy Partners, L.P., Holly Energy Finance Corp., and each of the
Guarantors party thereto and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Holly Energy
Partners, L.P.'s Current Report on Form 8-K filed July 19, 2016, File Number 1-32225).
First Supplemental Indenture, dated November 2, 2016, among Woods Cross Operating LLC, Holly Energy Partners,
L.P., and 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
September 30, 2016, File Number 1-32225).
Indenture, dated March 22, 2016, between HollyFrontier Corporation and Wells Fargo Bank, National Association
(incorporated by reference to Exhibit 4.1 of Registrant's Current Report on Form 8-K filed March 22, 2016, File No.
1-03876).
Supplemental Indenture, dated March 22, 2016, between HollyFrontier Corporation and Wells Fargo Bank, National
Association (incorporated by reference to Exhibit 4.2 of Registrant's Current Report on Form 8-K filed March 22,
2016, File No. 1-03876).
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).
104
Table of Content
Exhibit
Number
10.5
10.6
10.7
10.8
10.9
10.1
10.11*
10.12
10.13
10.14
10.15
Description
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).
Third Amended and Restated Crude Pipelines and Tankage Agreement, dated March 12, 2015, by and among Navajo
Refining Company, L.L.C., Holly Refining & Marketing Company - Woods Cross LLC, HollyFrontier Refining &
Marketing LLC, Holly Energy Partners-Operating, L.P., HEP Pipeline, L.L.C. and HEP Woods Cross L.L.C.
(incorporated by reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed March 16, 2015, File No.
1-03876).
Second Amended and Restated Refined Products Pipelines and Terminals Agreement, dated February 22, 2016, by
and among HollyFrontier Refining & Marketing LLC, HollyFrontier Corporation, Holly Energy Partners - Operating,
L.P. and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.3 of Registrant's Current Report on Form
8-K filed February 22, 2016, File No. 1-03876).
Second Amended and Restated Throughput Agreement (Tucson Terminal), dated September 19, 2013, effective June
1, 2013, among HollyFrontier Refining & Marketing LLC, HEP Refining, L.L.C. and Holly Energy Partners -
Operating, L.P. (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2013, File No. 1-03876).
Seventeenth Amended and Restated Omnibus Agreement, dated January 18, 2017, effective January 1, 2017, by and
among HollyFrontier Corporation, Holly Energy Partners, L.P. and certain of their respective subsidiaries.
Senior Unsecured 5-Year Revolving Credit Agreement, dated July 1, 2014, among HollyFrontier Corporation, as
borrower, Union Bank, N. A. as administrative agent, and each of the financial institutions party thereto as lenders
(incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed July 8, 2014, File No.
1-03876).
First Amendment to Senior Unsecured 5-Year Revolving Credit Agreement, dated as of February 16, 2017, among
HollyFrontier Corporation, as borrower, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as administrative agent, and the
lenders party thereto (incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed
February 21, 2017, File No. 1-03876).
Release of Subsidiary Guarantee, dated December 29, 2015, by and among HollyFrontier Corporation and Union
Bank, N.A. (incorporated by reference to Exhibit 10.40 of Registrant's Annual Report on Form 10-K for the fiscal
year ended December 31, 2015, 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).
10.16
Seventeenth Amendment, dated August 27, 2013, to the Frontier Products Offtake Agreement El Dorado Refinery,
dated October 19, 1999, between Frontier Oil and Refining Company (now HollyFrontier Refining & Marketing LLC,
as successor-by-merger to Frontier Oil and Refining Company) and Equiva Trading Company (now Shell Oil Products
US, assignee of Equiva Trading Company) (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly Report
on Form 10-Q for the quarterly period ended September 30, 2013, File No. 1-03876).
105
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
10.30*
10.31
10.32
Description
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).
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).
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).
Refined Products Purchase Agreement, dated December 1, 2009, between Holly Refining & Marketing - Tulsa LLC
and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 10.4 of Registrant's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876).
First Amendment to Refined Products Purchase Agreement, dated May 17, 2010, between Holly Refining & Marketing
- Tulsa LLC and Sinclair Tulsa Refining Company (incorporated by reference to Exhibit 10.5 of Registrant's Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876).
Second Amendment to Refined Products Purchase Agreement, dated December 19, 2011, between HollyFrontier
Refining & Marketing LLC and Sinclair Oil Corporation (incorporated by reference to Exhibit 10.6 of Registrant's
Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, File No 1-03876).
Third Amendment to Refined Products Purchase Agreement, dated June 1, 2012, between HollyFrontier Refining &
Marketing LLC and Sinclair Oil Corporation (incorporated by reference to Exhibit 10.7 of Registrant's Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 2013, File No. 1-03876).
Fourth Amendment to Refined Products Purchase Agreement, dated February 27, 2014, between HollyFrontier
Refining & Marketing LLC and Sinclair Oil Corporation (incorporated by reference to Exhibit 10.55 of Registrant's
Annual Report on Form 10-K for its fiscal year ended December 31, 2014, File No. 1-03876).
Fifth Amendment to Refined Products Purchase Agreement dated June 23, 2014, between HollyFrontier Refining &
Marketing LLC and Sinclair Oil Corporation (incorporated by reference to Exhibit 10.56 of Registrant's Annual Report
on Form 10-K for its fiscal year ended December 31, 2014, File No. 1-03876).
Amended and Restated Unloading and Blending Services Agreement, dated January 18, 2017, effective September
16, 2016, by and between HollyFrontier Refining & Marketing LLC, Holly Energy Partners - Operating, L.P. and
HEP Refining L.L.C.
Third Amended and Restated Master Throughput Agreement, dated January 18, 2017, effective January 1, 2017, by
and between HollyFrontier Refining & Marketing LLC and Holly Energy Partners - Operating, L.P.
Construction Payment Agreement, dated as of October 16, 2015, by and between HEP Refining, L.L.C. and
HollyFrontier Refining & Marketing LLC (incorporated by reference to Exhibit 10.3 of Registrant's Current Report
on Form 8-K filed October 21, 2015, File No. 1-03876).
Third Amended and Restated Services and Secondment Agreement, dated October 3, 2016, by and among Holly
Logistic Services, L.L.C., certain subsidiaries of Holly Energy Partners, L.P. and certain subsidiaries of HollyFrontier
Corporation (incorporated by reference to Exhibit 10.4 to Registrant's Current Report on Form 8-K filed October 4,
2016, File No. 1-03876).
Fourth Amended and Restated Master Lease and Access Agreement, dated January 18, 2017, effective January 1,
2017, by and among certain subsidiaries of Holly Energy Partners, L.P. and certain subsidiaries of HollyFrontier
Corporation.
Master Tolling Agreement (Refinery Assets), dated as of November 2, 2015, by and between Frontier El Dorado
Refining LLC and Holly Energy Partners-Operating L.P. (incorporated by reference to Exhibit 10.2 of Registrant's
Current Report on Form 8-K filed November 3, 2015, File No. 1-03876).
Amended and Restated Master Tolling Agreement (Operating Assets), dated October 3, 2016, by and between
HollyFrontier El Dorado Refining LLC, HollyFrontier Woods Cross Refining LLC, Holly Energy Partners - Operating
L.P., HollyFrontier Corporation and Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.2 to
Registrant's Current Report on Form 8-K filed October 4, 2016, File No. 1-03876).
106
Table of Content
Exhibit
Number
10.33
10.34
10.35
10.36
10.37
10.38+
10.39+
10.40+
10.41+
10.42+
10.43+
Description
LLC Interest Purchase Agreement, dated February 22, 2016, by and among HollyFrontier Refining & Marketing LLC,
HollyFrontier Corporation, Holly Energy Partners - Operating, L.P. and Holly Energy Partners, L.P. (incorporated by
reference to Exhibit 10.67 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2015,
File No. 1-03876).
Refined Products Terminal Transfer Agreement, dated February 22, 2016, by and among HEP Refining Assets, L.P.,
Holly Energy Partners, L.P., El Paso Logistics LLC, HollyFrontier Corporation and Holly Energy Partners - Operating,
L.P. (incorporated by reference to Exhibit 10.68 of Registrant's Annual Report on Form 10-K for its fiscal year ended
December 31, 2015, File No. 1-03876).
Second Amended and Restated Pipelines and Terminals Agreement, dated February 22, 2016, by and among
HollyFrontier Refining & Marketing LLC, HollyFrontier Corporation, Holly Energy Partners - Operating, L.P. and
Holly Energy Partners, L.P. (incorporated by reference to Exhibit 10.3 of Registrant's Current Report on Form 8-K
filed February 22, 2016, File No. 1-03876).
Pipeline Deficiency Agreement, dated August 8, 2016, by and between HollyFrontier Refining & Marketing LLC
and Holly Energy Partners - Operating, L.P. (incorporated by reference to Exhibit 10.5 to Registrant's Current Report
on Form 8-K filed August 10, 2016, File No. 1-03876).
LLC Interest Purchase Agreement, dated October 3, 2016, by and between HollyFrontier Corporation, HollyFrontier
Woods Cross Refining LLC, Holly Energy Partners - Operating, L.P. and Holly Energy Partners, L.P. (incorporated
by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed October 4, 2016, File No. 1-03876).
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).
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).
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).
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).
Fourth Amendment to the HollyFrontier Corporation Long-Term Incentive Compensation Plan (incorporated by
reference to Exhibit 10.2 of Registrant's Current Report on Form 8-K filed May 15, 2015, File No. 1-03876).
Fifth Amendment to the HollyFrontier Corporation Long-Term Incentive Plan, effective May 11, 2016 (incorporated
by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed May 16, 2016, File No. 1-03876).
10.44+* HollyFrontier Corporation Long-Term Incentive Plan UK Sub-Plan, effective February 14, 2017.
10.45+
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).
10.46+* Holly Corporation Employee Form of Change in Control Agreement.
10.47+
10.48+
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).
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).
10.49+* Form of Restricted Stock Agreement (time-based vesting).
10.50+* Form of Notice of Grant of Restricted Stock.
10.51+
Form of Restricted Stock Unit Agreement (for non-employee directors) (incorporated by reference to Exhibit 10.63
of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 1-03876).
107
Table of Content
Exhibit
Number
10.52+
10.53+
10.54+
Description
Form of Notice of Grant of Restricted Stock Units (for non-employee directors) (incorporated by reference to Exhibit
10.64 of Registrant's Annual Report on Form 10-K for its fiscal year ended December 31, 2012, File No. 1-03876).
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).
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).
10.55+
First Amendment to the HollyFrontier Corporation Omnibus Incentive Compensation Plan (incorporated by reference
to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed May 15, 2015, File No. 1-03876).
10.56+*
Second Amendment to the HollyFrontier Corporation Omnibus Incentive Compensation Plan, dated November 9,
2016.
10.57+
10.58+
10.59+
10.60+
21.1*
23.1*
31.1*
31.2*
HollyFrontier Corporation Executive Nonqualified Deferred Compensation Plan (formerly the Frontier Deferred
Compensation Plan) (incorporated by reference to Exhibit 10.73 of Registrant's Annual Report on Form 10-K for its
fiscal year ended December 31, 2012, File No. 1-03876).
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).
Retirement Agreement, dated January 13, 2017, between HollyFrontier Corporation and Douglas S. Aron
(incorporated by reference to Exhibit 10.1 of Registrant's Current Report on Form 8-K filed January 13, 2017, File
No. 1-03876).
Subsidiaries of Registrant
Consent of Independent of Registered Public Accounting Firm
Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
101++
The following financial information from Registrant's Annual Report on Form 10-K for its fiscal year ended December
31, 2016, 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.
108
I, George J. Damiris, 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 22, 2017
/s/ George J. Damiris
George J. Damiris
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 22, 2017
/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, 2016 and filed with the
Securities and Exchange Commission on the date hereof (the “Report”), I, George J. Damaris, 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 22, 2017
/s/ George J. Damiris
George J. Damiris
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, 2016 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 22, 2017
/s/ Douglas S. Aron
Douglas S. Aron
Executive Vice President and Chief Financial
Officer
CORPORATE OFFICERS
George J. Damiris
Chief Executive Officer and President
Richard L. Voliva III
Executive Vice President and
Chief Financial Officer
Thomas G. Creery
Senior Vice President, Commercial
James M. Stump
Senior Vice President, Refining
Denise C. McWatters
Senior Vice President, General Counsel
and Secretary
BOARD OF DIRECTORS
Michael C. Jennings
Chairman of the Board
of HollyFrontier Corporation
George J. Damiris
Chief Executive Officer and President
of HollyFrontier Corporation and
Holly Logistic Services, L.L.C.
Douglas Y. Bech
Chairman and Chief Executive Officer
of Raintree Resorts International
Leldon E. Echols
Investor
R. Kevin Hardage
CEO of Turtle Creek Trust Company, Co-founder,
President and Portfolio Manager of Turtle Creek
Management, L.L.C. and a non-controlling manager
and member of TCTC Holdings, L.L.C.
Robert J. Kostelnik
Principal at Glenrock Recovery Partners, L.L.C.
James H. Lee
Managing General Partner and Principal Owner
of Lee, Hite & Wisda Ltd.
Franklin Myers
Investor
Michael E. Rose
Investor
CORPORATE OFFICE
HollyFrontier Corporation
2828 North Harwood, Suite 1300
Dallas, TX 75201-1507
214.871.3555
www.hollyfrontier.com
AUDITORS
Ernst & Young LLP
Dallas, Texas
Design: Savage Brands, Houston Texas
STOCK EXCHANGE LISTING
New York Stock Exchange
Ticker Symbol: HFC
STOCK TRANSFER AGENT AND REGISTRAR
Wells Fargo Shareowner Services
1110 Centre Point Curve, Suite 101
Mendota Heights, MN 55120
1.800.468.9716
www.shareowneronline.com
Correspondence or questions concerning share
holdings, transfers, lost certificates, dividends,
or address or registration changes should be
directed to Wells Fargo Shareowner Services.
ANNUAL MEETING
The Annual Meeting of Stockholders will be held
at 8:30 a.m. Central Time, on May 10, 2017, at
2728 N. Harwood St., Ground Floor, Dallas, Texas 75201.
SEC FILINGS
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.
STOCK PERFORMANCE
Set forth is a line graph comparing, for the period commencing January 1,
2012, and ending December 31, 2016, 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 Securi-
ties Exchange of 1934, except to the extent that the Company specifically
incorporates such graph by reference.
HollyFrontier
S&P 500 Index
Peer Group
$500
$400
$300
$200
$100
$0
12/2011
12/2012
12/2013
12/2014
12/2015
12/2016
HollyFrontier
100
S&P 500 Index
100
Peer Group
100
216
116
185
247
154
279
200
175
286
219
177
375
188
198
369
(1) The amounts shown assume that the value of the investment in HollyFrontier
and each index was $100 on December 31, 2011 and that all dividends
were reinvested.
(2) The Peer Group consists of Alon USA Energy, Inc., Delek US Holdings, Inc.,
Marathon Petroleum Corporation, Tesoro Corporation, Valero Energy
Corporation and Western Refining, Inc.
Corporate Information 2828 North Harwood
Suite 1300
Dallas, Texas 75201-1507