10-K 1 hfc12-31x201310k.htm 10-K HFC 12-31-2013 10K



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________________________________________________________
FORM 10-K
_________________________________________________________________
(Mark One)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from    __________   to   ____________         
Commission File Number 1-3876
 _________________________________________________________________
HOLLYFRONTIER CORPORATION
(Exact name of registrant as specified in its charter)
_________________________________________________________________
Delaware
 
75-1056913
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
2828 N. Harwood, Suite 1300
Dallas, Texas
 
75201-1507
(Address of principal executive offices)
 
(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  ý    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  ý
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  ý    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  ý    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.       ý
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
ý
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  ý
On June 28, 2013, 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 $7.9 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.)
198,971,030 shares of Common Stock, par value $.01 per share, were outstanding on February 21, 2014.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's proxy statement for its annual meeting of stockholders to be held on May 14, 2014, which proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2013, are incorporated by reference in Part III.




TABLE OF CONTENTS


Item
Page
 
 
PART I
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
PART IV
 
 
 
 
 
 
 

2


PART I

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10‑K contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Form 10-K, including, but not limited to, those under “Business and Properties” in Items 1 and 2, “Risk Factors” in Item 1A, “Legal Proceedings” in Item 3 and “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, are forward-looking statements. These statements are based on management's beliefs and assumptions using currently available information and expectations as of the date hereof, are not guarantees of future performance and involve certain risks and uncertainties. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that our expectations will prove to be correct. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors including, but not limited to:

risks and uncertainties with respect to the actions of actual or potential competitive suppliers of refined petroleum products in our markets;
the demand for and supply of crude oil and refined products;
the spread between market prices for refined products and market prices for crude oil;
the possibility of constraints on the transportation of refined products;
the possibility of inefficiencies, curtailments or shutdowns in refinery operations or pipelines;
effects of governmental and environmental regulations and policies;
the availability and cost of our financing;
the effectiveness of our capital investments and marketing strategies;
our efficiency in carrying out construction projects;
our ability to acquire refined product operations or pipeline and terminal operations on acceptable terms and to integrate any existing or future acquired operations;
the possibility of terrorist attacks and the consequences of any such attacks;
general economic conditions; and
other financial, operational and legal risks and uncertainties detailed from time to time in our Securities and Exchange Commission filings.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Form 10-K, including without limitation the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Form 10-K under “Risk Factors” in Item 1A and in conjunction with the discussion in this Form 10-K in “Management's Discussion and Analysis of Financial Condition and Results of Operations” under the heading “Liquidity and Capital Resources.” All forward-looking statements included in this Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.



3


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 a alternative fuel produced from renewable biological resources.

Black wax crude oil” is a low sulfur, low gravity crude oil produced in the Uintah Basin in Eastern Utah that has certain characteristics that require specific facilities to transport, store and refine into transportation fuels.

Catalytic reforming” means a refinery process which uses a precious metal (such as platinum) based catalyst to convert low octane naphtha to high octane gasoline blendstock and hydrogen. The hydrogen produced from the reforming process is used to desulfurize other refinery oils and is a primary source of hydrogen for the refinery.

Cracking” means the process of breaking down larger, heavier and more complex hydrocarbon molecules into simpler and lighter molecules.

Crude distillation” means the process of distilling vapor from liquid crudes, usually by heating, and condensing the vapor slightly above atmospheric pressure turning it back to liquid in order to purify, fractionate or form the desired products.

Ethanol” means a high octane gasoline blend stock that is used to make various grades of gasoline.

FCC,” or fluid catalytic cracking, means a refinery process that breaks down large complex hydrocarbon molecules into smaller more useful ones using a circulating bed of catalyst at relatively high temperatures.

Hydrodesulfurization” means to remove sulfur and nitrogen compounds from oil or gas in the presence of hydrogen and a catalyst at relatively high temperatures.

Hydrogen plant” means a refinery unit that converts natural gas and steam to high purity hydrogen, which is then used in the hydrodesulfurization, hydrocracking and isomerization processes.

HF alkylation,” or hydrofluoric alkylation, means a refinery process which combines isobutane and C3/C4 olefins using HF acid as a catalyst to make high octane gasoline blend stock.

Isomerization” means a refinery process for rearranging the structure of C5/C6 molecules without changing their size or chemical composition and is used to improve the octane of C5/C6 gasoline blendstocks.

LPG” means liquid petroleum gases.

Lubricant” or “lube” means a solvent neutral paraffinic product used in 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



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.

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.

“WCS” means Western Canada Select crude oil and is made up of Canadian heavy conventional and bitumen crude oils blended with sweet synthetic and condensate diluents.

“WTI” means West Texas Intermediate and is a grade of crude oil used as a common benchmark in oil pricing. WTI is a sweet crude oil and has a relatively low density.

“WTS” means West Texas Sour, a medium sour crude oil.


5


Items 1 and 2. Business and Properties


COMPANY OVERVIEW

References herein to HollyFrontier Corporation (“HollyFrontier”) include HollyFrontier and its consolidated subsidiaries. In accordance with the Securities and Exchange Commission's (“SEC”) “Plain English” guidelines, this Annual Report on Form 10-K has been written in the first person. In this document, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person with certain exceptions. Generally, the words “we,” “our,” “ours” and “us” include Holly Energy Partners, L.P. (“HEP”) and its subsidiaries as consolidated subsidiaries of HollyFrontier, unless when used in disclosures of transactions or obligations between HEP and HollyFrontier or its other subsidiaries. This document contains certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.

We merged with Frontier Oil Corporation (“Frontier”) on July 1, 2011. Concurrent with the merger, we changed our name from Holly Corporation (“Holly”) to HollyFrontier and changed the ticker symbol for our common stock traded on the New York Stock Exchange to “HFC.” Accordingly, this document includes Frontier, its consolidated subsidiaries and the operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date.

We are principally an independent petroleum refiner that produces high-value refined 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.”

On February 21, 2011, we entered into a merger agreement providing for a “merger of equals” business combination between us and Frontier. On July 1, 2011, North Acquisition, Inc., a direct wholly-owned subsidiary of Holly, merged with and into Frontier, with Frontier surviving as a wholly-owned subsidiary of Holly. Subsequent to the merger and following approval by HollyFrontier's post-closing board of directors, Frontier merged with and into HollyFrontier, and HollyFrontier continued as the surviving corporation. This merger combined the legacy Frontier refinery operations consisting of refineries in El Dorado, Kansas (the “El Dorado Refinery”) and Cheyenne, Wyoming (the “Cheyenne Refinery”) with Holly’s legacy refinery operations to form HollyFrontier. The aggregate equity consideration paid in connection with the merger was $3.7 billion.

On June 1, 2009, we acquired an 85,000 BPSD refinery located in Tulsa, Oklahoma (the "Tulsa West facility") from an affiliate of Sunoco, Inc. ("Sunoco") for $157.8 million. On December 1, 2009, we acquired a 75,000 BPSD refinery from an affiliate of Sinclair Oil Company ("Sinclair") also located in Tulsa, Oklahoma (the "Tulsa East facility") for $183.3 million. We have integrated certain operations of the Tulsa West and East facilities (collectively, the "Tulsa Refineries"). This resulted in the Tulsa Refineries having an integrated crude processing rate of 125,000 BPSD.

HEP, a consolidated variable interest entity ("VIE") as defined under U.S. generally accepted accounting principles ("GAAP"), made several acquisitions between 2010 and 2012. Information on these acquisitions can be found under the “Holly Energy Partners, L.P.” section provided later in this discussion of Items 1 and 2, “Business and Properties.”


6


As of December 31, 2013, we:
owned and operated a petroleum refinery in El Dorado, Kansas (the “El Dorado Refinery”), two refinery facilities located in Tulsa, Oklahoma, a refinery in Artesia, New Mexico that is operated in conjunction with crude oil distillation and vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (collectively, the “Navajo Refinery”), a refinery located in Cheyenne, Wyoming (the “Cheyenne Refinery”) and a refinery in Woods Cross, Utah (the “Woods Cross Refinery”);
owned and operated NK Asphalt Partners (“NK Asphalt”) which operates various asphalt terminals in Arizona and New Mexico;
owned a 50% interest in Sabine Biofuels II, LLC (“Sabine Biofuels”), a biodiesel production facility located in Port Arthur, Texas; and
owned a 39% interest in HEP, a consolidated VIE, which includes our 2% general partner interest. HEP owns and operates logistic assets consisting of petroleum product and crude oil pipelines and terminal, tankage and loading rack facilities that principally support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States and Alon USA, Inc.'s (“Alon”) refinery in Big Spring, Texas. Additionally, HEP owns a 75% interest in UNEV Pipeline, LLC (“UNEV”), which owns a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada, together with terminal facilities in the Cedar City, Utah and North Las Vegas areas (the “UNEV Pipeline”), and a 25% interest in SLC Pipeline LLC (the “SLC Pipeline”), which owns a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.

Our operations are currently organized into two reportable segments, Refining and HEP. The Refining segment includes the operations of our El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries and NK Asphalt. The HEP segment involves all of the operations of HEP. The financial information about our segments is discussed in Note 20 “Segment Information” in the Notes to Consolidated Financial Statements.


REFINERY OPERATIONS

Our refinery operations serve the Mid-Continent, Southwest and Rocky Mountain regions of the United States. We own and operate five complex refineries having a combined crude oil processing capacity of 443,000 barrels per stream day. Each of our refineries has the complexity to convert discounted, heavy and sour crude oils into a high percentage of gasoline, diesel and other high-value refined products. For 2013, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 50%, 33%, 5% and 2%, respectively, of our total refinery sales volumes.

The tables presented below and elsewhere in this discussion of our refinery operations set forth information, including non-GAAP performance measures, about our refinery operations. The cost of products and refinery gross and net operating margins do not include the effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011 (10)
Consolidated
 
 
 
 
 
 
Crude charge (BPD) (1)
 
387,520

 
415,210

 
315,000

Refinery throughput (BPD) (2)
 
424,780

 
453,740

 
340,200

Refinery production (BPD) (3)
 
413,820

 
442,730

 
331,890

Sales of produced refined products (BPD)
 
410,730

 
431,060

 
332,720

Sales of refined products (BPD) (4)
 
446,390

 
443,620

 
340,630

Refinery utilization (5)
 
87.5
%
 
93.7
%
 
89.9
%


7


 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011 (10)
Consolidated
 
 
 
 
 
 
Average per produced barrel (6)
 
 
 
 
 
 
Net sales
 
$
115.60

 
$
119.48

 
$
118.82

Cost of products (7)
 
99.61

 
94.59

 
98.18

Refinery gross margin
 
15.99

 
24.89

 
20.64

Refinery operating expenses (8)
 
6.15

 
5.49

 
5.36

Net operating margin
 
$
9.84

 
$
19.40

 
$
15.28

 
 
 
 
 
 
 
Refinery operating expenses per throughput barrel (9)
 
$
5.95

 
$
5.22

 
$
5.24

 
 
 
 
 
 
 
Feedstocks:
 
 
 
 
 
 
Sweet crude oil
 
52
%
 
51
%
 
56
%
Sour crude oil
 
21
%
 
22
%
 
23
%
Heavy sour crude oil
 
17
%
 
17
%
 
12
%
Black wax crude oil
 
2
%
 
2
%
 
2
%
Other feedstocks and blends
 
8
%
 
8
%
 
7
%
Total
 
100
%
 
100
%
 
100
%

(1)
Crude charge represents the barrels per day of crude oil processed at our refineries.
(2)
Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries.
(3)
Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
(4)
Includes refined products purchased for resale.
(5)
Represents crude charge divided by total crude capacity (BPSD). Effective July 1, 2011, our consolidated crude capacity increased from 256,000 BPSD to 443,000 BPSD as a result of our merger with Frontier.
(6)
Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
(7)
Transportation, terminal and refinery storage costs billed from HEP are included in cost of products.
(8)
Represents operating expenses of our refineries, exclusive of depreciation and amortization and pension settlement costs.
(9)
Represents refinery operating expenses, exclusive of depreciation and amortization and pension settlement costs, divided by refinery throughput.
(10)
Refining operating data for the year ended December 31, 2011 include crude oil processed and products yielded from the El Dorado and Cheyenne Refineries for the period from July 1, 2011 through December 31, 2011 only, and averaged over the 365 days in the year ended December 31, 2011.

Principal Products and Customers
Set forth below is information regarding our principal products.
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
Consolidated
 
 
 
 
 
 
Sales of produced refined products:
 
 
 
 
 
 
Gasolines
 
50
%
 
50
%
 
48
%
Diesel fuels
 
33
%
 
31
%
 
32
%
Jet fuels
 
5
%
 
6
%
 
5
%
Fuel oil
 
2
%
 
2
%
 
2
%
Asphalt
 
3
%
 
3
%
 
4
%
Lubricants
 
2
%
 
3
%
 
3
%
Gas oil / intermediates
 
%
 
%
 
2
%
LPG and other
 
5
%
 
5
%
 
4
%
Total
 
100
%
 
100
%
 
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.


8


We have several significant customers, of which one accounted for more than 10% of our business in 2013. For the year ended December 31, 2013, Sinclair accounted for $2,134.3 million, or 11%, of our revenues. Our principal customers for gasoline include other refiners, convenience store chains, independent marketers and retailers. Diesel fuel is sold to other refiners, truck stop chains, wholesalers and railroads. Jet fuel is sold for 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 Tulsa West and East refinery facilities are both located in Tulsa, Oklahoma. In 2011, we integrated certain refining processes of the Tulsa Refineries which effectively provides us with a highly complex refining operation having a combined crude processing rate of approximately 125,000 barrels per stream day. For 2013, gasoline, diesel fuel, jet fuel and specialty lubricants (excluding volumes purchased for resale) represented 47%, 31%, 8% and 4%, respectively, of our Mid-Continent sales volumes.

The following table sets forth information about our Mid-Continent region operations, including non-GAAP performance measures.
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011 (10)
Mid-Continent Region (El Dorado and Tulsa Refineries)
 
 
 
 
 
 
Crude charge (BPD) (1)
 
234,930

 
248,360

 
183,070

Refinery throughput (BPD) (2)
 
257,030

 
269,760

 
194,310

Refinery production (BPD) (3)
 
251,470

 
263,310

 
188,760

Sales of produced refined products (BPD)
 
247,030

 
254,350

 
188,020

Sales of refined products (BPD) (4)
 
269,790

 
258,020

 
190,340

Refinery utilization (5)
 
90.4
%
 
95.5
%
 
94.8
%
 
 
 
 
 
 
 
Average per produced barrel (6)
 
 
 
 
 
 
Net sales
 
$
115.63

 
$
119.19

 
$
119.51

Cost of products (7)
 
99.35

 
95.77

 
99.92

Refinery gross margin
 
16.28

 
23.42

 
19.59

Refinery operating expenses (8)
 
5.50

 
4.83

 
5.04

Net operating margin
 
$
10.78

 
$
18.59

 
$
14.55

 
 
 
 
 
 
 
Refinery operating expenses per throughput barrel (9)
 
$
5.29

 
$
4.55

 
$
4.88

 
 
 
 
 
 
 
Feedstocks:
 
 
 
 
 
 
Sweet crude oil
 
69
%
 
70
%
 
82
%
Sour crude oil
 
6
%
 
8
%
 
4
%
Heavy sour crude oil
 
16
%
 
14
%
 
8
%
Other feedstocks and blends
 
9
%
 
8
%
 
6
%
Total
 
100
%
 
100
%
 
100
%

Footnote references are provided under our Consolidated Refinery Operating Data table on page 8.

The El Dorado Refinery is located on 1,100 acres south of El Dorado, Kansas and is a fully integrated refinery. The principal 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. Supporting infrastructure includes maintenance shops, warehouses, office buildings, a laboratory, utility facilities, and a wastewater plant (“Supporting Infrastructure”) and logistics assets owned by HEP, which includes approximately 3.6 million barrels of tankage, a truck sales terminal, and a propane terminal. The facility typically processes approximately 135,000 BPSD of crude oil with the capability to handle a significant volume of heavy sour crudes.


9


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, catalytic reforming, propane de-asphalting, lubes extraction, MEK dewaxing, delayed coker and butane splitter units. Most of the operating units at the facility currently in service were built in the late 1950s and early 1960s. The refinery was reconfigured to emphasize specialty lubricant production in the early 1990s. Tulsa West facility's Supporting Infrastructure includes approximately 3.2 million barrels of feedstock and product tankage, of which 0.4 million barrels of tankage is owned by Plains All American Pipeline, L.P. (“Plains”).

The Tulsa East facility is located on a 466-acre site also in Tulsa, Oklahoma situated along the Arkansas River. The principal process units at the Tulsa East facility consist of crude and vacuum distillation, naphtha hydrodesulfurization, FCC, isomerization, catalytic reforming, alkylation, scanfiner, diesel hydrodesulfurization and sulfur units. The Tulsa East facility's Supporting Infrastructure includes approximately 3.4 million barrels of tankage owned by HEP.

Markets and Competition
The primary markets for the El Dorado Refinery's refined products are Colorado and the Plains States, which include the Kansas City metropolitan area. The gasoline, diesel and jet fuel produced by the El Dorado Refinery are primarily shipped via pipeline to terminals for distribution by truck or rail. We ship product via the NuStar Pipeline Operating Partnership L.P. Pipeline to the northern Plains States, via the Magellan Pipeline Company, L.P. (“Magellan”) mountain pipeline to Denver, Colorado, and on the Magellan mid-continent pipeline to the Plains States.

The El Dorado Refinery faces competition from other Plains States and Mid-Continent refiners, but the principal competitors for the El Dorado Refinery are Gulf Coast refiners. Although our Gulf Coast competitors typically have lower production costs because of economies of scale, we believe that our competitors' higher refined product transportation costs allow our El Dorado Refinery to compete effectively in the Plains States and Rocky Mountain region with the Gulf Coast refineries.

For the year ended December 31, 2013, sales to Shell Oil Products US (“Shell”) represented approximately 27% of the El Dorado Refinery's total sales and 9% of our total consolidated sales. We have an offtake agreement with Shell under which Shell purchases gasoline, diesel and jet fuel production of the El Dorado Refinery at market-based prices through the end of 2014 primarily to support its branded and unbranded marketing network. We market gasoline and diesel primarily in Denver and throughout the Plains States.

The Tulsa Refineries primarily serve the Mid-Continent region of the United States. Distillates and gasolines are primarily delivered from the Tulsa Refineries to market via pipelines owned and operated by Magellan. These pipelines connect the refinery to distribution channels throughout Colorado, Oklahoma, Kansas, Missouri, Illinois, Iowa, Minnesota, Nebraska and Arkansas. Additionally, HEP's on-site truck and rail racks facilitate access to local refined product markets.

In conjunction with our acquisition of the Tulsa East facility in 2009, we entered a five-year offtake agreement through November 2014 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, 2013, sales to Sinclair represented approximately 36% of the Tulsa Refineries' total sales and 11% 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.

Our Tulsa West facility also produces specialty lubricant products sold in both commercial and specialty markets throughout North America and to customers with operations in Central America and South America. The specialty lubricant products are high value products that provide a significantly higher margin contribution to the refinery. Base oil customers include blender-compounders who prepare the various finished lubricant and grease products sold to end users. Agricultural products are formulated as supplemental carriers for herbicides and as Environmental Protection Agency (“EPA”) registered pesticide oils, are sold to product formulators. Process oil customers include rubber and chemical industry customers. Specialty waxes are sold primarily to packaging customers as coating material for paper and cardboard, and to non-packaging customers in the construction materials, adhesive and candle-making markets. Our production represents approximately 6% of paraffinic oil capacity and 13% of wax production capacity in the United States market and is one of four refineries of specialty aromatic oils in North America.


10


Principal Products
Set forth below is information regarding the principal products produced at our El Dorado and Tulsa Refineries:
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
Mid-Continent Region (El Dorado and Tulsa Refineries)
 
 
 
 
 
 
Sales of produced refined products:
 
 
 
 
 
 
Gasolines
 
47
%
 
48
%
 
44
%
Diesel fuels
 
31
%
 
29
%
 
32
%
Jet fuels
 
8
%
 
9
%
 
7
%
Fuel oil
 
1
%
 
1
%
 
%
Asphalt
 
3
%
 
2
%
 
4
%
Lubricants
 
4
%
 
5
%
 
6
%
Gas oil / intermediates
 
%
 
%
 
3
%
LPG and other
 
6
%
 
6
%
 
4
%
Total
 
100
%
 
100
%
 
100
%

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 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, Gulf of Mexico, Canadian and other foreign crudes. The proximity of the refineries to the Cushing pipeline and storage hub provides the flexibility to optimize their crude slate with a wide variety of crude oil supply options. 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 or to our Navajo Refinery.

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, naptha 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 2013, gasoline and diesel fuel (excluding volumes purchased for resale) represented 51% and 39%, respectively, of our Southwest sales volumes.

The following table sets forth information about our Southwest region operations, including non-GAAP performance measures.
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011 (10)
Southwest Region (Navajo Refinery)
 
 
 
 
 
 
Crude charge (BPD) (1)
 
87,910

 
93,830

 
83,700

Refinery throughput (BPD) (2)
 
97,310

 
103,120

 
93,260

Refinery production (BPD) (3)
 
94,490

 
100,810

 
91,810

Sales of produced refined products (BPD)
 
94,830

 
99,160

 
93,950

Sales of refined products (BPD) (4)
 
104,320

 
104,620

 
98,540

Refinery utilization (5)
 
87.9
%
 
93.8
%
 
83.7
%
 
 
 
 
 
 
 
Average per produced barrel (6)
 
 
 
 
 
 
Net sales
 
$
117.79

 
$
122.62

 
$
118.76

Cost of products (7)
 
103.88

 
95.70

 
98.40

Refinery gross margin
 
13.91

 
26.92

 
20.36

Refinery operating expenses (8)
 
6.04

 
6.07

 
5.44

Net operating margin
 
$
7.87

 
$
20.85

 
$
14.92

 
 
 
 
 
 
 
Refinery operating expenses per throughput barrel (9)
 
$
5.89

 
$
5.84

 
$
5.48



11


 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011 (10)
Southwest Region (Navajo Refinery)
 
 
 
 
 
 
Feedstocks:
 
 
 
 
 
 
Sweet crude oil
 
8
%
 
2
%
 
3
%
Sour crude oil
 
72
%
 
77
%
 
75
%
Heavy sour crude oil
 
11
%
 
12
%
 
11
%
Other feedstocks and blends
 
9
%
 
9
%
 
11
%
Total
 
100
%
 
100
%
 
100
%

Footnote references are provided under our Consolidated Refinery Operating Data table on page 8.

The Navajo Refinery's Artesia, New Mexico facility is located on a 561-acre site and is a fully integrated refinery with crude distillation, vacuum distillation, FCC, ROSE (solvent deasphalter), HF alkylation, catalytic reforming, hydrodesulfurization, mild hydrocracking, isomerization, sulfur recovery and product blending units. The operating units at the Artesia facility include newly constructed units, older units that have been relocated from other facilities and upgraded and re-erected in Artesia, and units that have been operating as part of the Artesia facility (with periodic major maintenance) for many years, in some very limited cases since before 1970. Supporting Infrastructure includes approximately 2.0 million barrels of feedstock and product tankage, of which 0.3 million barrels of tankage are owned by HEP.

The Artesia facility is operated in conjunction with a refining facility located in Lovington, New Mexico, approximately 65 miles east of Artesia. The principal equipment at the Lovington facility consists of a crude distillation unit and associated vacuum distillation units that were constructed after 1970. Supporting Infrastructure includes 1.1 million barrels of feedstock and product tankage of which 0.2 million barrels of tankage are owned by HEP. The Lovington facility processes crude oil into intermediate products that are transported to Artesia by means of three intermediate pipelines owned by HEP. These products are then upgraded into finished products at the Artesia facility. The combined crude oil capacity of the Navajo Refinery facilities is 100,000 BPSD and it typically processes or blends an additional 10,000 BPSD of natural gasoline, butane, gas oil and naphtha.

Markets and Competition
The Navajo Refinery primarily serves the southwestern United States market, which has historically experienced a high growth rate, including the metropolitan areas of El Paso, Texas; Albuquerque, Moriarty and Bloomfield, New Mexico; Phoenix and Tucson, Arizona; and portions of northern Mexico. Our products are shipped through HEP's pipelines from Artesia, New Mexico to El Paso, Texas and from El Paso to Albuquerque and to Mexico via products pipeline systems owned by 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 EnCana Corp.), Valero, Alon and Western Refining. Pipelines serving this market are owned by Magellan, NuStar Energy L.P. and HEP. Refined products from the Gulf Coast are transported via Magellan pipelines.

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.


12


We use a common carrier pipeline out of El Paso to serve the Albuquerque market. In addition, HEP leases from Mid-America Pipeline Company, L.L.C., a pipeline between White Lakes, New Mexico and the Albuquerque vicinity and Bloomfield, New Mexico. The lease agreement currently runs through 2017, and HEP has options to renew for two ten-year periods. HEP owns and operates a 12-inch pipeline from the Navajo Refinery to the leased pipeline as well as terminalling facilities in 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:
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
Southwest Region (Navajo Refinery)
 
 
 
 
 
 
Sales of produced refined products:
 
 
 
 
 
 
Gasolines
 
51
%
 
51
%
 
52
%
Diesel fuels
 
39
%
 
38
%
 
34
%
Jet fuels
 
%
 
%
 
1
%
Fuel oil
 
6
%
 
6
%
 
6
%
Asphalt
 
1
%
 
2
%
 
4
%
LPG and other
 
3
%
 
3
%
 
3
%
Total
 
100
%
 
100
%
 
100
%

Crude Oil and Feedstock Supplies
The Navajo Refinery is situated near the Permian Basin, an area that has historically, and continues to have, abundant supplies of crude oil available both for regional users and for export to other areas. We purchase crude oil from independent producers in southeastern New Mexico and west Texas as well as from major oil companies. The crude oil is gathered through HEP's pipelines, our tank trucks and through third-party crude oil pipeline systems for delivery to the Navajo Refinery.

The Navajo Refinery also has access to a wide variety of crude oils available at Cushing, Oklahoma via HEP's Roadrunner Pipeline that connects to Centurion Pipeline L.P. and to various pipelines and tank facilities located at Cushing, Oklahoma. In 2010, the Navajo Refinery began processing heavy sour crude oil transported from Cushing through these pipelines.

We also purchase volumes of isobutane, natural gasoline and other feedstocks to supply the Navajo Refinery from sources in Texas and the Mid-Continent area that are delivered to our region on a common carrier pipeline owned by Enterprise Products, L.P. Ultimately all volumes of these products are shipped to the Artesia refining facilities on HEP's intermediate pipelines running from Lovington to Artesia. From time to time, we purchase gas oil, naphtha and light cycle oil from other refiners for use as feedstock.

Rocky Mountain Region (Cheyenne and Woods Cross Refineries)

Facilities
The Cheyenne Refinery has a crude oil processing capacity of 52,000 barrels per stream day and the Woods Cross Refinery has a crude oil capacity of 31,000 barrels per stream day. The Cheyenne Refinery processes heavy Canadian crudes as well as local sweet crudes such as that produced from the Bakken shale and similar resources. The Woods Cross Refinery processes regional sweet and black wax crude as well as Canadian sour crude oils into high value light products. For 2013, gasoline and diesel fuel (excluding volumes purchased for resale) represented 56% and 30%, respectively, of our Rocky Mountain sales volumes.


13


The following table sets forth information about our Rocky Mountain region operations, including non-GAAP performance measures.
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011 (10)
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)
 
 
 
 
 
 
Crude charge (BPD) (1)
 
64,680

 
73,020

 
48,230

Refinery throughput (BPD) (2)
 
70,440

 
80,860

 
52,630

Refinery production (BPD) (3)
 
67,860

 
78,610

 
51,320

Sales of produced refined products (BPD)
 
68,870

 
77,550

 
50,750

Sales of refined products (BPD) (4)
 
72,280

 
80,980

 
51,750

Refinery utilization (5)
 
77.9
%
 
88.0
%
 
84.3
%
 
 
 
 
 
 
 
Average per produced barrel (6)
 
 
 
 
 
 
Net sales
 
$
112.49

 
$
116.44

 
$
116.37

Cost of products (7)
 
94.63

 
89.29

 
91.33

Refinery gross margin
 
17.86

 
27.15

 
25.04

Refinery operating expenses (8)
 
8.65

 
6.91

 
6.41

Net operating margin
 
$
9.21

 
$
20.24

 
$
18.63

 
 
 
 
 
 
 
Refinery operating expenses per throughput barrel (9)
 
$
8.46

 
$
6.63

 
$
6.18

 
 
 
 
 
 
 
Feedstocks:
 
 
 
 
 
 
Sweet crude oil
 
43
%
 
47
%
 
52
%
Sour crude oil
 
1
%
 
1
%
 
1
%
Heavy sour crude oil
 
34
%
 
31
%
 
24
%
Black wax crude oil
 
14
%
 
11
%
 
15
%
Other feedstocks and blends
 
8
%
 
10
%
 
8
%
Total
 
100
%
 
100
%
 
100
%

Footnote references are provided under our Consolidated Refinery Operating Data table on page 8.

The Cheyenne Refinery facility is located on a 255-acre site and is a fully integrated refinery with crude distillation, vacuum distillation, coking, FCCU, HF alkylation, catalytic reforming, hydrodesulfurization of naphtha and distillates, butane isomerization, hydrogen production, sulfur recovery and product blending units. The operating units at the Cheyenne Refinery include both newly constructed units and older units that have been upgraded over the years. Supporting Infrastructure includes approximately 1.9 million barrels of feedstock and product tankage owned by HEP.

The Woods Cross Refinery facility is located on a 200-acre site and is a fully integrated refinery with crude distillation, solvent deasphalter, FCC, HF alkylation, catalytic reforming, hydrodesulfurization, isomerization, sulfur recovery and product blending units. The operating units at the Woods Cross Refinery include newly constructed units, older units that have been relocated from other facilities, upgraded and re-erected in Woods Cross, and units that have been operating as part of the Woods Cross facility (with periodic major maintenance) for many years, in some very limited cases since before 1950. Supporting Infrastructure includes approximately 1.5 million barrels of feedstock and product tankage, of which 0.2 million barrels of tankage are owned by HEP. The facility typically processes or blends an additional 2,000 BPSD of natural gasoline, butane and gas oil over its 31,000 BPSD capacity.

We own and operate 4 miles of hydrogen pipeline that connects the Woods Cross Refinery to a hydrogen plant located 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 are expanding the Woods Cross refinery to a planned capacity of 45,000 BPSD at an anticipated cost of approximately $300.0 million. 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. The matter is now pending before an administrative law judge of the Utah Department of Environmental Quality. The expansion is expected to be completed in the fourth quarter of 2015. The expansion scope includes the relocation / revamp of crude, fluid catalytic cracking, and polymerization units as well an expansion of the diesel hydrotreater. The expansion, and expected completion timeline and cost, are subject to the Woods Cross refinery successfully obtaining the Approval Order.

14



In conjunction with the expansion, we signed a 10-year, 20,000 BPD crude oil supply agreement with Newfield Exploration Company. This agreement, which commences upon completion of the expansion, will supply black and yellow wax crude oil produced in the nearby Uinta Basin to the Woods Cross Refinery. Upon completion of this expansion, the Woods Cross Refinery's capacity to process waxy crude is expected to double to approximately 24,000 BPD.

Markets and Competition
The Cheyenne Refinery primarily markets its products in eastern Colorado, including metropolitan Denver, eastern Wyoming and western Nebraska. Because of the location of the Cheyenne Refinery, we are able to sell a significant portion of its diesel from the truck rack at the refinery, thus eliminating transportation costs. Pipeline shipments from the Cheyenne Refinery are on the 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 150,000 BPD of crude oil. The five Utah refineries collectively supply an estimated 70% of the gasoline and distillate products consumed in the states of Utah and Idaho, with the remainder imported from refineries in Wyoming and Montana via the Pioneer Pipeline owned jointly by Sinclair and Phillips 66. Approximately 40% - 45% of the gasoline and diesel fuel produced by our Woods Cross Refinery is sold through a network of Phillips 66 branded marketers under a long-term supply agreement.

Idaho, Wyoming, Eastern Washington and Nevada Markets
We supply a small percentage of the refined products consumed in the combined Idaho, Wyoming, eastern Washington and Nevada markets. Our Woods Cross Refinery ships refined products over 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:
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
Rocky Mountain Region (Cheyenne and Woods Cross Refineries)
 
 
 
 
 
 
Sales of produced refined products:
 
 
 
 
 
 
Gasolines
 
56
%
 
55
%
 
56
%
Diesel fuels
 
30
%
 
32
%
 
31
%
Jet fuels
 
1
%
 
%
 
1
%
Fuel oil
 
1
%
 
2
%
 
1
%
Asphalt
 
5
%
 
5
%
 
6
%
LPG and other
 
7
%
 
6
%
 
5
%
Total
 
100
%
 
100
%
 
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 Kinder Morgan, Plains All American Pipeline and Suncor Energy, as well as by truck. The Woods Cross Refinery currently obtains crude oil from suppliers in Canada, Wyoming, Utah and Colorado as delivered via common carrier pipelines that originate in Canada, Wyoming and Colorado. 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.


15


NK Asphalt Partners

We manufacture and market commodity and modified asphalt products in Arizona, New Mexico, Oklahoma, Kansas, Missouri, Texas and northern Mexico. We have three manufacturing facilities located in Glendale, Arizona; Albuquerque, New Mexico; and Artesia, New Mexico. Our Albuquerque and Artesia facilities manufacture modified hot asphalt products and commodity emulsions from base asphalt materials provided by our refineries and third-party suppliers. Our Glendale facility manufactures modified hot asphalt products from base asphalt materials provided by our refineries and third-party suppliers. Our products are shipped via third-party trucking companies to commercial customers that provide asphalt based materials for commercial and government projects.

Other Assets

We own a 50% joint venture interest in Sabine Biofuels II, LLC, a 30 million gallon per year biodiesel production facility located near Port Arthur, Texas.


HOLLY ENERGY PARTNERS, L.P.

HEP is a Delaware limited partnership that trades on the New York Stock Exchange under the trading symbol “HEP.” HEP was formed to acquire, own and operate substantially all of the refined product pipeline and terminalling assets that support our refining and marketing operations in the Mid-Continent, Southwest and Rocky Mountain regions of the United States.

HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by leasing certain pipeline capacity to Alon, by charging fees for terminalling refined products and other hydrocarbons and by storing and providing other services at its storage tanks and terminals. HEP does not take ownership of products that it transports or terminals; therefore, it is not directly exposed to changes in commodity prices.

HEP's recent acquisitions (2009 through present) are summarized below:

UNEV Interest Transaction
On July 12, 2012, HEP acquired from us our 75% interest in UNEV. We received consideration consisting of $260.0 million in cash and 1.0 million HEP common units. UNEV owns the UNEV Pipeline, a 12-inch refined products pipeline running from Salt Lake City, Utah to Las Vegas, Nevada together with terminal facilities in Cedar City, Utah and North Las Vegas. The UNEV Pipeline was completed in late 2011 and became operational during the first quarter of 2012.

Legacy Frontier Pipeline and Tankage Asset Transaction
On November 9, 2011, HEP acquired from us certain tankage, loading rack and crude receiving assets located at our El Dorado and Cheyenne Refineries. We received non-cash consideration consisting of promissory notes with an aggregate principal amount of $150.0 million and 3.8 million HEP common units.

Tulsa East / Lovington Storage Asset Transaction
On March 31, 2010, HEP acquired from us certain storage assets for $93.0 million, consisting of hydrocarbon storage tanks having approximately 2.0 million barrels of storage capacity, a rail loading rack and a truck unloading rack located at our Tulsa East facility and an asphalt loading rack facility located at our Navajo Refinery facility located in Lovington, New Mexico.

Sinclair Logistics and Storage Assets Transaction
On December 1, 2009, HEP acquired from Sinclair storage tanks having approximately 1.4 million barrels of storage capacity and loading racks at what is now our Tulsa East facility for $79.2 million.

Roadrunner / Beeson Pipelines Transaction
Also on December 1, 2009, HEP acquired our two newly constructed pipelines for $46.5 million, consisting of a 65-mile, 16-inch crude oil pipeline (the “Roadrunner Pipeline”) that connects our Navajo Refinery Lovington facility to a terminus of Centurion Pipeline L.P.'s pipeline extending between west Texas and Cushing, Oklahoma and a 37-mile, 8-inch crude oil pipeline that connects HEP's New Mexico crude oil gathering system to our Navajo Refinery Lovington facility (the “Beeson Pipeline”).

Tulsa West Loading Racks Transaction
On August 1, 2009, HEP acquired from us, certain truck and rail loading/unloading facilities located at our Tulsa West facility for $17.5 million.


16


Lovington-Artesia Pipeline Transaction
On June 1, 2009, HEP acquired our newly constructed, 16-inch intermediate pipeline for $34.2 million that runs 65 miles from our Navajo Refinery's crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery located in Artesia, New Mexico.

SLC Pipeline Joint Venture Interest
On March 1, 2009, HEP acquired a 25% joint venture interest in the SLC Pipeline, a new 95-mile intrastate pipeline system jointly owned with Plains. HEP's capitalized joint venture contribution was $25.5 million.

Rio Grande Pipeline Sale
On December 1, 2009, HEP sold its 70% interest in Rio Grande Pipeline Company (“Rio Grande”) to a subsidiary of Enterprise Products Partners LP for $35.0 million.

Transportation Agreements

Agreements with HEP
HEP serves our refineries under long-term pipeline and terminal, tankage and throughput agreements expiring in 2019 through 2026. Under these agreements, we pay HEP fees to transport, store and throughput volumes of refined product and crude oil on HEP's pipeline and terminal, tankage and loading rack facilities that result in minimum annual payments to HEP including UNEV (a consolidated subsidiary of HEP). Under these agreements, the agreed upon tariff rates are subject to annual tariff rate adjustments on July 1 at a rate based upon the percentage change in Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index. As of December 31, 2013, these agreements result in minimum annualized payments to HEP of $225.5 million.

Since HEP is a consolidated VIE, our transactions with HEP including the transactions discussed above and fees paid under our transportation agreements with HEP and UNEV, a consolidated subsidiary of HEP, are eliminated and have no impact on our consolidated financial statements.

Agreement with Alon
HEP has a 15-year pipelines and terminals agreement with Alon expiring in 2020, under which Alon has agreed to transport on HEP's pipelines and throughput through its terminals, volumes of refined products that results in a minimum level of annual revenue. The agreed upon tariff rates are increased or decreased annually at a rate equal to the percentage change in PPI, but will not decrease below the initial tariff rate. Also, HEP has a capacity lease agreement with Alon under which Alon leases space on HEP's Orla to El Paso pipeline for the shipment of up to 15,000 barrels of refined product per day. The terms under this agreement expire in 2018 through 2022.

As of December 31, 2013, 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;
three 65-mile pipelines that transport intermediate feedstocks and crude oil from our Navajo Refinery crude oil distillation and vacuum facilities in Lovington, New Mexico to our petroleum refinery facilities in Artesia, New Mexico;
approximately 970 miles of crude oil trunk, gathering and connection pipelines located in west Texas, New Mexico and Oklahoma that deliver crude oil to our Navajo Refinery;
approximately 10 miles of refined product pipelines that support our Woods Cross Refinery located near Salt Lake City, Utah;
gasoline and diesel connecting pipelines that support our Tulsa East facility;
five intermediate product and gas pipelines between the Tulsa East and Tulsa West facilities; and
crude receiving assets located at our Cheyenne Refinery.

Refined Product Terminals and Refinery Tankage
four refined product terminals located in El Paso, Texas; Moriarty and Bloomfield, New Mexico; and Tucson, Arizona, with an aggregate capacity of approximately 1,300,000 barrels, that are integrated with HEP's refined product pipeline system that serves our Navajo Refinery;
one refined product terminal located in Spokane, Washington, with a capacity of approximately 400,000 barrels, that serves third-party common carrier pipelines;

17


one refined product terminal near Mountain Home, Idaho, with a capacity of 120,000 barrels, that serves a nearby United States Air Force Base;
two refined product terminals, located in Wichita Falls and Abilene, Texas, and one tank farm in Orla, Texas with aggregate capacity of approximately 500,000 barrels, that are integrated with HEP's refined product pipelines that serve Alon's Big Spring, Texas refinery;
a refined product loading rack facility at each of our El Dorado, Tulsa, Navajo, Cheyenne and Woods Cross Refineries, heavy product / asphalt loading rack facilities at our Tulsa East facility, Navajo Refinery Lovington facility and Cheyenne Refinery, LPG loading rack facilities at our El Dorado Refinery, Tulsa West facility and Cheyenne Refinery, lube oil loading racks at our Tulsa West facility and crude oil Leased Automatic Custody Transfer (“LACT”) units located at our Cheyenne Refinery;
on-site crude oil tankage at our Tulsa, Navajo, Cheyenne and Woods Cross Refineries having an aggregate storage capacity of approximately 1,200,000 barrels; and
on-site refined and intermediate product tankage at our El Dorado, Tulsa and Cheyenne Refineries having an aggregate storage capacity of approximately 8,400,000 barrels.

Additionally, HEP owns a 75% interest in UNEV, which owns the UNEV Pipeline, a 12-inch refined products pipeline from Salt Lake City, Utah to Las Vegas, Nevada together with terminal facilities in the Cedar City, Utah and North Las Vegas areas, and a 25% interest in SLC Pipeline LLC, which owns a 95-mile intrastate pipeline system that serves refineries in the Salt Lake City area.


ADDITIONAL OPERATIONS AND OTHER INFORMATION

Corporate Offices
We lease approximately 60,000 square feet for our principal corporate offices in Dallas, Texas. The lease for our principal corporate offices expires in 2021. Functions performed in the Dallas office include overall corporate management, refinery and HEP management, planning and strategy, corporate finance, crude acquisition, logistics, contract administration, marketing, investor relations, governmental affairs, accounting, tax, treasury, information technology, legal and human resources support functions.

Employees and Labor Relations
As of December 31, 2013, we had 2,662 employees, of which 886 are currently covered by collective bargaining agreements having various expiration dates between 2015 and 2018. We consider our employee relations to be good.

Regulation
Refinery and pipeline operations are subject to numerous federal, state and local laws regulating the discharge of substances into the environment or otherwise relating to the protection of the environment. Permits are required under these laws for the operation of our refineries, pipelines and related facilities, and these permits are subject to revocation, modification and renewal. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, the results of operations, and our capital requirements. We believe that our current operations are in substantial compliance with applicable federal, state, and local environmental laws, regulations, and permits.

Our operations and many of the products we manufacture are subject to certain requirements of the Federal Clean Air Act (“CAA”) as well as related state and local laws and regulations. Certain CAA regulatory programs applicable to our refineries require capital expenditures for the installation of certain air pollution control devices. Additionally, the EPA has the authority under the CAA to modify the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. Subsequent rulemaking authorized by the CAA or similar laws, or new agency interpretations of existing laws and regulations, may necessitate additional expenditures in future years.

Also, we are subject to the EPA's new Control of Hazardous Air Pollutants from Mobile Sources (“MSAT2”) regulations on gasoline that impose reductions in the benzene content of our produced gasoline. Our refineries currently purchase a portion of their benzene credits to meet these requirements. If economically justified, we could implement additional benzene reduction projects to eliminate the need to purchase benzene credits.


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The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 prescribe certain percentages of renewable fuels (e.g., ethanol and biofuels) that, where required, must be blended into our produced gasoline and diesel. Additional changes in fuel standards, tier III standards, to reduce vehicle emissions are expected to be finalized by the end of February 2014. These new requirements, other requirements of the CAA, and other presently existing or future environmental regulations may, where required, cause us to make substantial capital expenditures and purchase credits at significant cost to enable our refineries to produce products that meet applicable requirements.

Further regulatory requirements have emerged from concerns over the potential climate impacts of certain "greenhouse gases" such as carbon dioxide and methane. In response to a statutory directive, the EPA has promulgated rules requiring the reporting of greenhouse gas emissions. In 2010, the EPA promulgated regulations applying construction and operating permit requirements under the CAA's Prevention of Significant Deterioration and Title V programs to sources with potential greenhouse gas emissions above certain threshold levels. The EPA has also announced its intention to issue a New Source Performance Standard directly regulating greenhouse gas emissions from refineries. Proposals both expanding and limiting the EPA's authority in this area continue to be considered in Congress. Litigation challenging the EPA's authority over greenhouse gas emissions also is pending in federal court. The U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) decided in 2012 to uphold the rules, but the U.S. Supreme Court has agreed to review that decision.

Our operations are also subject to the Federal Clean Water Act (“CWA”), the Federal Safe Drinking Water Act (“SDWA”) and comparable state and local requirements. The CWA, the SDWA and analogous laws prohibit any discharge into surface waters, ground waters, injection wells and publicly-owned treatment works except in conformance with legal authorization, such as pre-treatment permits and National Pollutant Discharge Elimination System (“NPDES”) permits, issued by federal, state and local governmental agencies. NPDES permits and analogous water discharge permits are valid for a maximum of five years and must be renewed.

We generate wastes that may be subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state and local requirements. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons, including the current and past owner or operator of the disposal site or sites from which there is a release of a “hazardous substance,” as well as persons that disposed of or arranged for the disposal or treatment of the hazardous substances at the site or sites. Under CERCLA, such persons may be subject to joint and several liability for such costs as the cost of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. In the course of our historical operations, as well as in our current normal operations, we have generated waste, some of which falls within the statutory definition of a “hazardous substance” and some of which may have been disposed of at sites that may be subject to cleanup and cost recovery actions under CERCLA by a government entity or other third party. Similarly, locations now owned or operated by us, where third parties have disposed such hazardous substances in the past, may also be subject to cleanup and cost recovery actions under CERCLA. Under CERCLA, liable parties may seek contribution from other liable parties to share in the costs of cleanup. Some states have enacted laws similar to CERCLA which impose similar responsibilities and liabilities on responsible parties. It is also not uncommon for neighboring landowners and other third parties to file claims under state law for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. These matters include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of. We currently have environmental remediation projects that relate to recovery, treatment and monitoring activities resulting from past releases of refined product and crude oil into the environment. As of December 31, 2013, we had an accrual of $87.8 million related to such environmental liabilities.

We are and have been the subject of various state, federal and private proceedings and inquiries relating to compliance with environmental regulations and conditions, including those discussed above. Compliance with current and future environmental regulations is expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our refineries and at pipeline transportation facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued, if applicable.

Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures.

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Health and environmental legislation and regulations change frequently. We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Compliance with more stringent laws or regulations or adverse changes in the interpretation of existing laws or regulations by government agencies could have an adverse effect on our financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.
 
Insurance
Our operations are subject to hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.

We have a risk management oversight committee that is made up of members from our senior management. This committee oversees our risk enterprise program, monitors our risk environment and provides direction for activities to mitigate identified risks that may adversely affect the achievement of our goals.



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Item 1A.
Risk Factors

Investing in us involves a degree of risk, including the risks described below. Our operating results have been, and will continue to be, affected by a wide variety of risk factors, many of which are beyond our control, that could have adverse effects on profitability during any particular period. You should carefully consider the following risk factors together with all of the other information included in this Annual Report on Form 10-K, including the financial statements and related notes, when deciding to invest in us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business operations. If any of the following risks were to actually occur, our business, financial condition or results of operations could be materially and adversely affected.

The prices of crude oil and refined products materially affect our profitability, and are dependent upon many factors that are beyond our control, including general market demand and economic conditions, seasonal and weather-related factors, regional and grade differentials and governmental regulations and policies.

Among these factors is the demand for crude oil and refined products, which is largely driven by the conditions of local and worldwide economies as well as by weather patterns and the taxation of these products relative to other energy sources. Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, also have a significant impact on our activities. Operating results can be affected by these industry factors, product and crude pipeline capacities, changes in transportation costs, accidents or interruptions in transportation, competition in the particular geographic areas that we serve, and factors that are specific to us, such as the success of particular marketing programs and the efficiency of our refinery operations. The demand for crude oil and refined products can also be reduced due to a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline and diesel fuel, higher gasoline prices due to higher crude oil prices, a shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel.

We do not produce crude oil and must purchase all our crude oil, the price of which fluctuates based upon worldwide and local market conditions. Our profitability depends largely on the spread between market prices for refined petroleum products and crude oil prices. This margin is continually changing and may fluctuate significantly from time to time. Crude oil and refined products are commodities whose price levels are determined by market forces beyond our control. For example, the reversal of certain existing pipelines or the construction of certain new pipelines transporting additional crude oil or refined products to markets that serve competing refineries could affect the market dynamic that has allowed us to take advantage of favorable pricing. Additionally, due to the seasonality of refined products markets and refinery maintenance schedules, results of operations for any particular quarter of a fiscal year are not necessarily indicative of results for the full year 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.

We may not be able to successfully execute our business strategies to grow our business. Further, if we are unable to complete capital projects at their expected costs or in a timely manner, if we are unsuccessful in integrating the operations of assets we acquire, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be materially and adversely affected.

One of the ways we may grow our business is through the construction of new refinery processing units (or the purchase and refurbishment of used units from another refinery) and the expansion of existing ones. Projects are generally initiated to increase the yields of higher-value products, increase the amount of lower cost crude oils that can be processed, increase refinery production capacity, meet new governmental requirements, or maintain the operations of our existing assets. Additionally, our growth strategy includes projects that permit access to new and/or more profitable markets. The construction process involves numerous regulatory, environmental, political, and legal uncertainties, most of which are not fully within our control, including:


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denial or delay in issuing requisite regulatory approvals and/or permits;
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 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:

diversion of management time and attention from our existing business;
challenges in managing the increased scope, geographic diversity and complexity of operations and inefficiencies that may result therefrom;
difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;
liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;
greater than anticipated expenditures required for compliance with environmental or other regulatory standards or for investments to improve operating results;
difficulties or delays in achieving anticipated operational improvements or benefits;
incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets; and
issuance of additional equity, which could result in further dilution of the ownership interest of existing stockholders.

Any acquisitions that we do consummate may have adverse effects on our business and operating results.


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We may incur significant costs to comply with new or changing environmental, energy, health and safety laws and regulations, and face potential exposure for environmental matters.

Refinery and pipeline operations are subject to federal, state and local laws regulating, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances 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. Permits are required under these laws for the operation of our refineries, pipelines and related operations, and these permits are subject to revocation, modification and renewal or may require operational changes, which may involve significant costs. Furthermore, a violation of permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or refinery shutdowns. In addition, major modifications of our operations due to changes in the law could require changes to our existing permits or expensive upgrades to our existing pollution control equipment, which could have a material adverse effect on our business, financial condition, or results of operations. Over the years, there have been and continue to be ongoing communications, including notices of violations, and discussions about environmental matters between us and federal and state authorities, some of which have resulted or will result in changes to operating procedures and in capital expenditures. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on our operations, results of operations and capital requirements.

As is the case with all companies engaged in industries similar to ours, we face potential exposure to future claims and lawsuits involving environmental matters. The matters include, 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 state, federal and private proceedings relating to environmental regulations, conditions and inquiries. Current and future environmental regulations are expected to require additional expenditures, including expenditures for investigation and remediation, which may be significant, at our facilities. To the extent that future expenditures for these purposes are material and can be reasonably determined, these costs are disclosed and accrued.

Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. Failure to appropriately manage occupational health and safety risks associated with our business could also adversely impact our employees, communities, stakeholders, reputation and results of operations.

We cannot predict what additional health and environmental legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. However, new environmental laws and regulations, including new regulations relating to alternative energy sources and the risk of global climate change, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require us to make additional unforeseen expenditures. The EPA has begun regulating certain emissions of greenhouse gases, or “GHGs,” (including carbon dioxide, methane and nitrous oxides) from large stationary sources like refineries under the authority of the CAA, and it is possible that Congress could pass federal legislation that creates a comprehensive GHG regulatory program, either directly or indirectly, such as via a federal renewal energy standard. Also, new federal or state legislation or regulatory programs that restrict emissions of GHGs in areas where we conduct business could adversely affect demand for our products and our results of operations.

The costs of environmental and safety regulations are already significant and compliance with more stringent laws or regulations or adverse changes in the interpretation of existing regulations by government agencies could have an adverse effect on the financial position and the results of our operations and could require substantial expenditures for the installation and operation of systems and equipment that we do not currently possess.

From time to time, new federal energy policy legislation is enacted by the U.S. Congress. For example, in December 2007, the U.S. Congress passed the Energy Independence and Security Act, which, among other provisions, mandates annually increasing levels for the use of renewable fuels such as ethanol, commencing in 2008 and escalating for 15 years, as well as increasing energy efficiency goals, including higher fuel economy standards for motor vehicles, among other steps. These statutory mandates may have the impact over time of offsetting projected increases in the demand for refined petroleum products in certain markets, particularly gasoline. In the near term, the new renewable fuel standard presents ethanol production and logistics challenges for both the ethanol and refining industries and may require additional capital expenditures or expenses by us to accommodate increased ethanol use. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.


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For additional information on regulations and related liabilities or potential liabilities affecting our business, see “Regulation” under Items 1 and 2, “Business and Properties,” and Item 3, “Legal Proceedings.”

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the refined products we produce.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal CAA. The EPA also adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which may require permits for emissions of GHGs from certain large stationary sources. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions were upheld by the D.C. Circuit, but the U.S. Supreme Court has agreed to review that decision in response to petitions by numerous parties. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis. The EPA has also announced its intention to issue a New Source Performance Standard directly regulating GHG emissions from refineries.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. These cap and trade programs generally work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and on an annual basis surrender emission allowances. The number of allowances available for purchase is reduced over time in an effort to achieve the overall GHG emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the refined products that we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

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. 

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, power failures, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage or destruction of property, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments. We maintain significant insurance coverage, but it does not cover all potential losses, costs or liabilities, and our business interruption insurance coverage generally does not apply unless a business interruption exceeds 45 days. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs.

The availability of adequate insurance may be affected by conditions in the insurance market over which we have no control, resulting in the inability to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase or, in some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.


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The energy industry is highly capital intensive, and the entire or partial loss of individual facilities can result in significant costs to both industry companies, such as us, and their insurance carriers. In recent years, several large energy industry claims have resulted in significant increases in the level of premium costs and deductible periods for participants in the energy industry. As a result of large energy industry claims, insurance companies that have historically participated in underwriting energy-related facilities may discontinue that practice or demand significantly higher premiums or deductible periods to cover these facilities. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, or if other adverse conditions over which we have no control prevail in the insurance market, we may be unable to obtain and maintain adequate insurance at reasonable cost. In addition, we cannot assure you that our insurers will renew our insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. Further, our underwriters could have credit issues that affect their ability to pay claims. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.

The availability and cost of renewable identification numbers 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 Renewable Fuel Standard 2 (“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 renewable identification numbers (“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. 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 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.

To successfully operate our petroleum refining facilities, we are required to expend significant amounts for capital outlays and operating expenditures.

The refining business is characterized by high fixed costs resulting from the significant capital outlays associated with refineries, terminals, pipelines and related facilities. We are dependent on the production and sale of quantities of refined products at refined product margins sufficient to cover operating costs, including any increases in costs resulting from future inflationary pressures or market conditions and increases in costs of fuel and power necessary in operating our facilities. Furthermore, future major capital investment, various environmental compliance related projects, regulatory requirements or competitive pressures could result in additional capital expenditures, which may not produce a return on investment. Such capital expenditures may require significant financial resources that may be contingent on our access to capital markets and commercial bank loans. Additionally, other matters, such as regulatory requirements or legal actions, may restrict our access to funds for capital expenditures.

Our refineries consist of many processing units, a number of which have been in operation for many years. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating. We have taken significant measures to expand and upgrade units in our refineries by installing new equipment and redesigning older equipment to improve refinery capacity. The installation and redesign of key equipment at our refineries involves significant uncertainties, including the following: our upgraded equipment may not perform at expected throughput levels; operating costs of the upgraded equipment may be higher than expected; the yield and product quality of new equipment may differ from design and/or specifications and redesign, modification or replacement of the equipment may be required to correct equipment that does not perform as expected, which could require facility shutdowns until the equipment has been redesigned or modified. Any of these risks associated with new equipment, redesigned older equipment, or repaired equipment could lead to lower revenues or higher costs or otherwise have a negative impact on our future financial condition and results of operations.

In addition, we expect to execute turnarounds at our refineries, which involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen costs. The turnarounds allow us to perform maintenance, upgrades, overhaul and repair of process equipment and materials, during which time all or a portion of the refinery will be under scheduled downtime.


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Competition in the refining and marketing industry is intense, and an increase in competition in the markets in which we sell our products could adversely affect our earnings and profitability.

We compete with a broad range of refining and marketing companies, including certain multinational oil companies. Because of their geographic diversity, larger and more complex refineries, integrated operations and greater resources, some of our competitors may be better able to withstand volatile market conditions, to obtain crude oil in times of shortage and to bear the economic risks inherent in all areas of the refining industry.

We are not engaged in petroleum exploration and production activities and do not produce any of the crude oil feedstocks used at our refineries. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. Certain of our competitors, however, obtain a portion of their feedstocks from company-owned production and have retail outlets. Competitors that have their own production or extensive retail outlets, with brand-name recognition, are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

In recent years there have been several refining and marketing consolidations or acquisitions between entities competing in our geographic market. These transactions could increase the future competitive pressures on us.

The markets in which we compete may be impacted by competitors' plans for expansion projects and refinery improvements that could increase the production of refined products in our areas of operation and significantly affect our profitability.

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 material decrease in the supply of crude oil available to our refineries could significantly reduce our production levels.

To maintain or increase production levels at our refineries, we must continually contract for crude oil supplies from third parties. A material decrease in crude oil production from the fields that supply our refineries, as a result of depressed commodity prices, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil available to our refineries. In addition, any prolonged disruption of a significant pipeline that is used in supplying crude oil to our refineries or the potential operation of a new, converted or expanded crude oil pipeline that transports crude oil to other markets could result in a decline in the volume of crude oil available to our refineries. Such an event could result in an overall decline in volumes of refined products processed at our refineries and therefore a corresponding reduction in our cash flow. In addition, the future growth of our operations will depend in part upon whether we can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in our currently connected supplies. If we are unable to secure additional crude oil supplies of sufficient quality or crude pipeline expansion to our refineries, we will be unable to take full advantage of current and future expansion of our refineries' production capacities.

A disruption to or proration of the refined product distribution systems we utilize could negatively impact our profitability.

We utilize various common carrier or other third party pipeline systems to deliver our products to market. The key systems utilized by 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.


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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.

We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

The domestic and global financial markets and economic conditions are disrupted and volatile from time to time due to a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions and uncertainty in the financial services sector. In addition, the fixed-income markets have experienced periods of extreme volatility, which negatively impacted market liquidity conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from these markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under any existing revolving credit facility and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or we may be required to sell assets. Moreover, without adequate funding, we may be unable to execute our growth strategy, complete future acquisitions or construction projects, take advantage of other business opportunities or respond to competitive pressures, comply with regulatory requirements, or meet our short-term or long-term working capital requirements, any of which could have a material adverse effect on our revenues and results of operations. Failure to comply with regulatory requirements in a timely manner or meet our short-term or long-term working capital requirements could subject us to regulatory action.

We 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 39% interest in HEP, including the 2% general partner interest. HEP operates a system of crude oil and petroleum product pipelines, distribution terminals and refinery tankage in Arizona, Idaho, Kansas, New Mexico, Oklahoma, Texas, Utah, Washington and Wyoming. HEP generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, 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. 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, 2013.


27


We are exposed to the credit risks, and certain other risks, of our key customers and vendors.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We derive a significant portion of our revenues from contracts with key customers.

If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. In addition, nonperformance by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability to successfully conduct our business.

Any substantial increase in the nonpayment and/or nonperformance by our customers or vendors could have a material adverse effect on our results of operations and cash flows.

Terrorist attacks, and the threat of terrorist attacks or domestic vandalism, have resulted in increased costs to our business. Continued global hostilities or other sustained military campaigns may adversely impact our results of operations.

The long-term impacts of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on the energy transportation industry in general, and on us in particular, are not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business. Future terrorist attacks could lead to even stronger, more costly initiatives or regulatory requirements. Uncertainty surrounding continued global hostilities or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. Any one of, or a combination of, these occurrences could have a material adverse effect on our business, financial condition and results of operations.

Changes in the insurance markets attributable to terrorist attacks could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt.

Increases in required fuel economy and regulation of CO2 emissions from motor vehicles may reduce demand for transportation fuels.

In 2010, the EPA and the National Highway Traffic Safety Administration (“NHTSA”) finalized new standards, raising the required Corporate Average Fuel Economy (“CAFE”) of the nation's passenger fleet by 40% to approximately 35 miles per gallon (“m.p.g.”) by 2016 and imposing the first-ever federal GHG emissions standards on cars and light trucks. In September 2011, the EPA and the Department of Transportation finalized first-time standards for fuel economy of medium and heavy duty trucks. On August 28, 2012 the EPA and NHTSA adopted standards through model year 2025 in two phases. The first phase establishes final standards for 2017-2021 model year vehicles that are projected to require 40.3 - 41.0 m.p.g. in model year 2021 on an average industry fleet-wide basis. The second phase of the CAFE program represents non-final “augural” standards for 2022-2025 model year vehicles that are projected to require 48.7 - 49.7 m.p.g. in model year 2025, on an average industry fleet-wide basis. Such increases in fuel economy standards, along with mandated increases in use of renewable fuels discussed above, could result in decreasing demand for petroleum fuels. Decreasing demand for petroleum fuels could have a material effect on our financial condition and results of operation.

We may be unable to pay future regular and/or special dividends.

We will only be able to pay dividends from our available cash on hand, cash from operations or borrowings under our credit agreement. The declaration of future regular and/or special dividends on our common stock will be at the discretion of our board of directors and will depend upon many factors, including our results of operations, financial condition, earnings, capital requirements, and restrictions in our debt agreements and legal requirements. We cannot assure you that any dividends will be paid or the frequency of such payments.


28


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.

Our debt agreements contain operating and financial restrictions that might constrain our business and financing activities.

The operating and financial restrictions and covenants in our credit 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, investments, indebtedness and dividends; (ii) a prohibition on changes in control and (iii) restrictions on engaging in mergers, consolidations and sales of assets, entering into certain lease obligations, and making certain investments or capital expenditures. If we fail to satisfy the covenants set forth in the credit facility or another event of default occurs under the facility, the maturity of the loan could be accelerated or we could be prohibited from borrowing for our future working capital needs and issuing letters of credit. We might not have, or be able to obtain, sufficient funds to make these immediate payments. 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. In addition, our obligations under our credit facility are secured by inventory, receivables and pledged cash assets. If we are unable to repay our indebtedness under our credit facility when due, the lenders could seek to foreclose on the assets or we may be required to contribute additional capital to our subsidiaries. Any of these outcomes could have a material adverse effect on our business, financial condition and results of operations.

29



Our business may suffer due to a change in the composition of our Board of Directors, or by the 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, 2013, approximately 33% 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 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.


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.


30


While the outcome and impact on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

Environmental Matters
We are reporting the following proceedings to comply with SEC regulations which require us to disclose proceedings arising under federal, state or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings may result in monetary sanctions of $100,000 or more. Our respective subsidiaries have or will develop corrective action plans regarding these disclosures that will be implemented in consultation with the respective federal and state agencies. It is not possible to predict the ultimate outcome of these proceedings, although none are currently expected to have a material effect on our consolidated financial position.

Frontier Refining LLC (“FR”), our wholly-owned subsidiary, has undertaken environmental audits at the Cheyenne Refinery regarding compliance with federal and state environmental requirements. By letters dated October 5, 2012, and November 7, 2012, and January 10, 2013, and pursuant to EPA's audit policy to the extent applicable, FR 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, FR 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. Additional self-disclosures and follow-up correspondence are anticipated as the audit activities are completed. No further action has been taken by either agency at this time. The Cheyenne Refinery also has four outstanding Notices of Violations issued in 2010, 2011 and 2013 that are subject to ongoing settlement negotiations with the WDEQ. Additional air and other environmental audits for the Cheyenne Refinery are scheduled for 2014.

Between November 2010 and February 2012, certain of our subsidiaries submitted multiple reports to the EPA to voluntarily disclose non-compliance with fuels regulations at the Cheyenne, El Dorado, Navajo, Tulsa and Woods Cross refineries and at the Cedar City, Utah and Henderson, Colorado terminals. The EPA has requested additional information regarding certain of these reports, and our subsidiaries have complied with all requests received to date.
Other
We are a party to various other litigation and proceedings that we believe, based on advice of counsel, will not either individually or in the aggregate have a materially adverse impact on our financial condition, results of operations or cash flows.



Item 4.
Mine Safety Disclosures

Not Applicable.



31


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
2013
 
 
 
 
 
 
 
 
Fourth quarter
 
$
50.63

 
$
39.65

 
$
0.800

 
230,186,600

Third quarter
 
$
47.21

 
$
38.98

 
$
0.800

 
174,416,900

Second quarter
 
$
52.87

 
$
39.96

 
$
0.800

 
229,246,900

First quarter
 
$
59.20

 
$
42.76

 
$
0.800

 
217,439,700

 
 
 
 
 
 
 
 
 
2012
 
 
 
 
 
 
 
 
Fourth quarter
 
$
47.39

 
$
36.22

 
$
0.700

 
161,950,900

Third quarter
 
$
42.33

 
$
33.92

 
$
1.150

 
171,023,300

Second quarter
 
$
36.10

 
$
28.05

 
$
0.650

 
232,551,400

First quarter
 
$
36.45

 
$
23.96

 
$
0.600

 
230,380,300


In January 2012, our Board of Directors approved a $350 million stock repurchase program, and in June 2012, approved an additional $350 million repurchase program that authorizes us to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and other relevant considerations. These programs may be discontinued at any time by the Board of Directors. The following table includes repurchases made under this program during the fourth quarter of 2013.
Period
 
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
October 2013
 
423,800

 
$
42.80

 
423,800

 
$
313,327,358

November 2013
 
40,000

 
$
43.90

 
40,000

 
$
311,571,488

December 2013 (1)
 
475,000

 
$
47.83

 

 
$
311,571,488

Total for October to December 2013
 
938,800

 
 
 
463,800

 
 

(1) The December 2013 shares repurchased were not purchased under our approved stock repurchase program, but rather pursuant to separate authority from our Board of Directors. These repurchases were made in the open market.

As of February 11, 2014, we had approximately 127,580 stockholders, including beneficial owners holding shares in street name.

We intend to consider the declaration of a dividend on a quarterly basis, although there is no assurance as to future dividends since they are dependent upon future earnings, capital requirements, our financial condition and other factors. Our credit agreement and senior notes limit the payment of dividends. See Note 12 “Debt” in the Notes to Consolidated Financial Statements.



32


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.

 
Years Ended December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
 
(In thousands, except per share data)
FINANCIAL DATA (1)
 
 
 
 
 
 
 
 
 
For the period
 
 
 
 
 
 
 
 
 
Sales and other revenues
$
20,160,560

 
$
20,090,724

 
$
15,439,528

 
$
8,322,929

 
$
4,834,268

Income from continuing operations before income taxes
1,159,399

 
2,787,995

 
1,641,695

 
192,363

 
43,803

Income tax provision
391,576

 
1,027,962

 
581,991

 
59,312

 
7,460

Income from continuing operations
767,823

 
1,760,033

 
1,059,704

 
133,051

 
36,343

Income from discontinued operations, net of taxes (2)

 

 

 

 
16,926

Net income
767,823

 
1,760,033

 
1,059,704

 
133,051

 
53,269

Less net income attributable to noncontrolling interest
31,981

 
32,861

 
36,307

 
29,087

 
33,736

Net income attributable to HollyFrontier stockholders
$
735,842

 
$
1,727,172

 
$
1,023,397

 
$
103,964

 
$
19,533

Earnings per share attributable to HollyFrontier stockholders - basic
$
3.66

 
$
8.41

 
$
6.46

 
$
0.98

 
$
0.20

Earnings per share attributable to HollyFrontier stockholders - diluted
$
3.64

 
$
8.38

 
$
6.42

 
$
0.97

 
$
0.20

Cash dividends declared per common share
$
3.20

 
$
3.10

 
$
1.34

 
$
0.30

 
$
0.30

Average number of common shares outstanding:
 
 
 
 
 
 
 
 
 
Basic
200,419

 
204,379

 
157,948

 
106,436

 
100,836

Diluted
201,234

 
205,274

 
158,756

 
107,218

 
101,206

 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
869,174

 
$
1,662,687

 
$
1,338,391

 
$
283,255

 
$
211,545

Net cash provided by (used for) investing activities
$
(526,735
)
 
$
(711,104
)
 
$
228,494

 
$
(213,232
)
 
$
(534,603
)
Net cash provided by (used for) financing activities
$
(1,160,035
)
 
$
(772,788
)
 
$
(217,082
)
 
$
34,482

 
$
406,849

 
 
 
 
 
 
 
 
 
 
At end of period
 
 
 
 
 
 
 
 
 
Cash, cash equivalents and investments in marketable securities
$
1,665,263

 
$
2,393,401

 
$
1,840,610

 
$
230,444

 
$
125,819

Working capital
$
2,221,954

 
$
2,815,821

 
$
2,030,063

 
$
313,580

 
$
257,899

Total assets
$
10,056,739

 
$
10,328,997

 
$
9,576,243

 
$
3,049,951

 
$
2,766,318

Total debt (3)
$
997,519

 
$
1,336,238

 
$
1,214,742

 
$
810,561

 
$
707,458

Total equity
$
6,609,398

 
$
6,642,658

 
$
5,835,900

 
$
1,288,139

 
$
1,207,781


(1)
We merged with Frontier on July 1, 2011. Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011. See “Company Overview” under Items 1 and 2, “Business and Properties” for information on our merger.
(2)
On December 1, 2009, HEP sold its 70% interest in Rio Grande. Results of operations of Rio Grande are presented in discontinued operations.
(3)
Includes total HEP debt of $807.6 million, $864.7 million, $525.9 million, $482.3 million and $379.2 million, respectively, which is non-recourse to HollyFrontier.



33


Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Item 7 contains “forward-looking” statements. See “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. In this document, the words “we,” “our,” “ours” and “us” refer only to HollyFrontier and its consolidated subsidiaries or to HollyFrontier or an individual subsidiary and not to any other person with certain exceptions. Generally, the words “we,” “our,” “ours” and “us” include HEP and its subsidiaries as consolidated subsidiaries of HollyFrontier, unless when used in disclosures of transactions or obligations between HEP and HollyFrontier or its other subsidiaries. This document contains certain disclosures of agreements that are specific to HEP and its consolidated subsidiaries and do not necessarily represent obligations of HollyFrontier. When used in descriptions of agreements and transactions, “HEP” refers to HEP and its consolidated subsidiaries.

We merged with Frontier on July 1, 2011. Accordingly, this document includes Frontier, its consolidated subsidiaries and the operations of the merged Frontier businesses effective July 1, 2011, but not prior to this date.

Overview

We are principally an independent petroleum refiner that produces high-value refined products such as gasoline, diesel fuel, jet fuel, specialty lubricant products, and specialty and modified asphalt. We own and operate refineries having a combined crude oil processing capacity of 443,000 barrels per day that serve markets throughout the Mid-Continent, Southwest and Rocky Mountain regions of the United States. Our refineries are located in El Dorado, Kansas (the El Dorado Refinery), Tulsa, Oklahoma (the Tulsa Refineries), which comprise two production facilities, the Tulsa West and East facilities, a petroleum refinery in Artesia, New Mexico, which operates in conjunction with crude, vacuum distillation and other facilities situated 65 miles away in Lovington, New Mexico (the Navajo Refinery), Cheyenne, Wyoming (the Cheyenne Refinery) and Woods Cross, Utah (the Woods Cross Refinery).

For the year ended December 31, 2013, net income attributable to HollyFrontier stockholders was $735.8 million compared to $1,727.2 million for the year ended December 31, 2012.

Overall gross refining margins per produced product sold decreased 36% over the year ended December 31, 2012 due principally to significant contraction in WTI to Brent crude differentials as well as lower discounts on heavy sour crudes purchased during the second and third quarters of 2013.

Net income for the year ended December 31, 2013 reflects pension settlement and debt extinguishment charges of $39.5 million and $22.1 million, respectively. Also affecting current year net income were the effects of planned turnarounds at our El Dorado, Tulsa and Navajo Refineries as well as unplanned downtime incurred at each of our El Dorado and Cheyenne Refineries due to FCC unit issues during the second quarter of 2013.

Our financial and operating results additionally reflect lower crude oil throughput rates for the Southwest region, which averaged 74,370 BPD for the fourth quarter of 2013 compared to 99,610 BPD for the same period last year, as a result of waste water constraints at our Navajo Refinery during late 2013. This matter was resolved in January 2014 and throughput rates have since returned to planned levels.


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). This differential constantly changes and at times can be volatile. While we have experienced wide differentials (with Brent prices in excess of WTI prices) in recent years, which have significantly enhanced our profitability, the differential between Brent and WTI narrowed significantly during the second half of 2013 - averaging approximately one-half of the differential experienced during 2012. Differentials are likely to continue to be volatile in the near term. However, we expect the Brent to WTI differential to rebound upon completion of additional northern tier pipeline capacity into Cushing, Oklahoma, which we believe will create a surplus of light sweet crude oil on the U.S. Gulf Coast. Ultimately, we believe pipeline tariffs from Cushing to the Gulf Coast plus marine transportation costs to transport product from the Gulf Coast to alternative markets will set the inland - coastal differential.


34


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. As of December 2013, we are purchasing RINs in order to meet approximately half of our renewable fuel requirements. 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 due to real or perceived future shortages in RINs. As a result, we expect to continue to experience higher than historical costs to comply with the renewable fuel mandate. In the wholesale markets we serve, we are seeing price adjustments to indicate that the cost of RINs is being largely borne by the consumer at the pump. However, we continue to use various approaches to mitigate our exposure to the increasing cost of RINs, which include additional renewable fuel blending, shifts in our refined product slate and changes in the way we conduct marketing operations. We cannot predict with certainty whether and to what extent we will be successful in mitigating our exposure to increased RINs costs, and anticipate that increased compliance costs may negatively impact our future results of operations. In 2013, our ethanol RINs purchases from third parties totaled approximately 215 million RINs.

A more detailed discussion of our financial and operating results for the years ended December 31, 2013, 2012 and 2011 is presented in the following sections.


35


Results Of Operations

Financial Data
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011 (1)
 
 
(In thousands, except per share data)
Sales and other revenues
 
$
20,160,560

 
$
20,090,724

 
$
15,439,528

Operating costs and expenses:
 
 
 
 
 
 
Cost of products sold (exclusive of depreciation and amortization)
 
17,392,227

 
15,840,643

 
12,680,078

Operating expenses (exclusive of depreciation and amortization)
 
1,090,850

 
994,966

 
748,081

General and administrative expenses (exclusive of depreciation and amortization)
 
127,963

 
128,101

 
120,114

Depreciation and amortization
 
303,446

 
242,868

 
159,707

Total operating costs and expenses
 
18,914,486

 
17,206,578

 
13,707,980

Income from operations
 
1,246,074

 
2,884,146

 
1,731,548

Other income (expense):
 
 
 
 
 
 
Earnings (loss) of equity method investments
 
(2,072
)
 
2,923

 
2,300

Interest income
 
5,556

 
4,786

 
1,284

Interest expense
 
(68,050
)
 
(104,186
)
 
(78,323
)
Loss on early extinguishment of debt
 
(22,109
)
 

 

Gain on sale of marketable securities
 

 
326

 

Merger transaction costs
 

 

 
(15,114
)
 
 
(86,675
)
 
(96,151
)
 
(89,853
)
Income before income taxes
 
1,159,399

 
2,787,995

 
1,641,695

Income tax provision
 
391,576

 
1,027,962

 
581,991

Net income
 
767,823

 
1,760,033

 
1,059,704

Less net income attributable to noncontrolling interest
 
31,981

 
32,861

 
36,307

Net income attributable to HollyFrontier stockholders
 
$
735,842

 
$
1,727,172

 
$
1,023,397

Earnings per share attributable to HollyFrontier stockholders:
 
 
 
 
 
 
Basic
 
$
3.66

 
$
8.41

 
$
6.46

Diluted
 
$
3.64

 
$
8.38

 
$
6.42

Cash dividends declared per common share
 
$
3.20

 
$
3.10

 
$
1.34

Average number of common shares outstanding:
 
 
 
 
 
 
Basic
 
200,419

 
204,379

 
157,948

Diluted
 
201,234

 
205,274

 
158,756


(1) Our consolidated financial and operating results reflect the operations of the merged Frontier businesses beginning July 1, 2011.

Other Financial Data
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In thousands)
Net cash provided by operating activities
 
$
869,174

 
$
1,662,687

 
$
1,338,391

Net cash provided by (used for) investing activities
 
$
(526,735
)
 
$
(711,104
)
 
$
228,494

Net cash used for financing activities
 
$
(1,160,035
)
 
$
(772,788
)
 
$
(217,082
)
Capital expenditures
 
$
425,127

 
$
335,263

 
$
374,241

EBITDA (1)
 
$
1,515,467

 
$
3,097,402

 
$
1,842,134



36


(1)
Earnings before interest, taxes, depreciation and amortization, which we refer to as “EBITDA,” is calculated as net income plus (i) interest expense, net of interest income, (ii) income tax provision, and (iii) depreciation and amortization. EBITDA is not a calculation provided for under GAAP; however, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for financial covenants. EBITDA presented above is reconciled to net income under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.

Our operations are organized into two reportable segments, Refining and HEP. See Note 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 effect of depreciation and amortization. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011 (10)
Consolidated
 
 
 
 
 
 
Crude charge (BPD) (1)
 
387,520

 
415,210

 
315,000

Refinery throughput (BPD) (2)
 
424,780

 
453,740

 
340,200

Refinery production (BPD) (3)
 
413,820

 
442,730

 
331,890

Sales of produced refined products (BPD)
 
410,730

 
431,060

 
332,720

Sales of refined products (BPD) (4)
 
446,390

 
443,620

 
340,630

Refinery utilization (5)
 
87.5
%
 
93.7
%
 
89.9
%
 
 
 
 
 
 
 
Average per produced barrel (6)
 
 
 
 
 
 
Net sales
 
$
115.60

 
$
119.48

 
$
118.82

Cost of products (7)
 
99.61

 
94.59

 
98.18

Refinery gross margin
 
15.99

 
24.89

 
20.64

Refinery operating expenses (8)
 
6.15

 
5.49

 
5.36

Net operating margin
 
$
9.84

 
$
19.40

 
$
15.28

 
 
 
 
 
 
 
Refinery operating expenses per throughput barrel (9)
 
$
5.95

 
$
5.22

 
$
5.24


(1)
Crude charge represents the barrels per day of crude oil processed at our refineries.
(2)
Refinery throughput represents the barrels per day of crude and other refinery feedstocks input to the crude units and other conversion units at our refineries.
(3)
Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstocks through the crude units and other conversion units at our refineries.
(4)
Includes refined products purchased for resale.
(5)
Represents crude charge divided by total crude capacity (BPSD). Effective July 1, 2011, our consolidated crude capacity increased from 256,000 BPSD to 443,000 BPSD as a result of our merger with Frontier.
(6)
Represents average per barrel amount for produced refined products sold, which is a non-GAAP measure. Reconciliations to amounts reported under GAAP are provided under “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K.
(7)
Transportation, terminal and refinery storage costs billed from HEP are included in cost of products.
(8)
Represents operating expenses of our refineries, exclusive of depreciation and amortization and pension settlement costs.
(9)
Represents refinery operating expenses, exclusive of depreciation and amortization and pension settlement costs, divided by refinery throughput.
(10)
Refining operating data for the year ended December 31, 2011 include crude oil processed and products yielded from the El Dorado and Cheyenne Refineries for the period from July 1, 2011 through December 31, 2011 only, and averaged over the 365 days in the year ended December 31, 2011.



37


Results of Operations – Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Summary
Net income attributable to HollyFrontier stockholders for the year ended December 31, 2013 was $735.8 million ($3.66 per basic and $3.64 per diluted share), a $991.4 million decrease compared to $1,727.2 million ($8.41 per basic and $8.38 per diluted share) for the year ended December 31, 2012. Net income decreased due principally to a year-over-year decrease in refining margins, refinery downtime and pension settlement and debt extinguishment charges. Refinery gross margins for the year ended December 31, 2013 decreased to $15.99 per produced barrel from $24.89 for the year ended December 31, 2012.

Sales and Other Revenues
Sales and other revenues increased slightly from $20,090.7 million for the year ended December 31, 2012 to $20,160.6 million for the year ended December 31, 2013 due to higher refined product sales volumes, partially offset by a decrease in year-over-year sales prices. The average sales price we received per produced barrel sold decreased 3% from $119.48 for the year ended December 31, 2012 to $115.60 for the year ended December 31, 2013. Refined product sales volumes for the current period reflect higher volumes of purchased products, comprising 8% of total refined products sales compared to 3% for the year ended December 31, 2012 due to a decrease in refinery production and corresponding sales volumes of produced product as a result of planned turnaround and maintenance projects at our refineries and other unplanned refinery outages during the current year. Sales and other revenues for the years ended December 31, 2013 and 2012 include $53.4 million and $47.6 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold
Cost of products sold increased 10% from $15,840.6 million for the year ended December 31, 2012 to $17,392.2 million for the year ended December 31, 2013, due principally to higher refined product sales volumes and crude costs for the current year. The sales volume increase is attributable to higher sales volumes of purchased products caused in part, by planned turnaround projects and unplanned refinery outages during the year ended December 31, 2013. 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 increased 5% from $94.59 for the year ended December 31, 2012 to $99.61 for the year ended December 31, 2013.

Gross Refinery Margins
Gross refinery margin per produced barrel decreased 36% from $24.89 for the year ended December 31, 2012 to $15.99 for the year ended December 31, 2013. This was due to a decrease in average per barrel sales prices for refined products sold combined with increased crude oil and feedstock prices for the current year. Gross refinery margin does not include the effects of depreciation and amortization. See “Reconciliations to Amounts Reported Under Generally Accepted Accounting Principles” following Item 7A of Part II of this Form 10-K for a reconciliation to the income statement of prices of refined products sold and cost of products purchased.

Operating Expenses
Operating expenses, exclusive of depreciation and amortization, increased 10% from $995.0 million for the year ended December 31, 2012 to $1,090.9 million for the year ended December 31, 2013 due principally to higher repair and maintenance and fuel costs during the current year period and $31.7 million in pension settlement costs, partially offset by a decrease in environmental remediation costs. For the years ended December 31, 2013 and 2012, operating expenses include $95.7 million and $88.9 million, respectively, in costs attributable to HEP operations.

General and Administrative Expenses
General and administrative expenses were $128.0 million and $128.1 million for the years ended December 31, 2013 and 2012, respectively. For the years ended December 31, 2013 and 2012, general and administrative expenses include $9.4 million and $5.3 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses
Depreciation and amortization increased 25% from $242.9 million for the year ended December 31, 2012 to $303.4 million for the year ended December 31, 2013. The increase was due principally to depreciation and amortization attributable to capitalized improvement projects and capitalized refinery turnaround costs. For the years ended December 31, 2013 and 2012, depreciation and amortization expenses include $64.7 million and $57.8 million, respectively, in costs attributable to HEP operations.

Interest Income
Interest income for the year ended December 31, 2013 was $5.6 million compared to $4.8 million for the year ended December 31, 2012. This increase was due to interest received on increased investments in marketable debt securities during the current year period.


38


Interest Expense
Interest expense was $68.1 million for the year ended December 31, 2013 compared to $104.2 million for the year ended December 31, 2012. This decrease was due to lower year-over-year debt levels principally as a result of the redemption of our $286.8 million 9.875% senior notes in June 2013 and $200 million 8.5% senior notes in September 2012. For the years ended December 31, 2013 and 2012, interest expense included $46.8 million and $57.2 million, respectively, in interest costs attributable to HEP operations.

Loss on Early Extinguishment of Debt
In June 2013, we redeemed our $286.8 million aggregate principal amount of 9.875% senior notes maturing June 2017 at a redemption cost of $301.0 million, at which time we recognized a $22.1 million early extinguishment loss consisting of a $14.2 million debt redemption premium and an unamortized discount of $7.9 million.

Income Taxes
For the year ended December 31, 2013, we recorded income tax expense of $391.6 million compared to $1,028.0 million for the year ended December 31, 2012. This decrease was due principally to lower pre-tax earnings during the year ended December 31, 2013 compared to the same period of 2012. Our effective tax rates, before consideration of earnings attributable to the noncontrolling interest, were 33.8% and 36.9% for the years ended December 31, 2013 and 2012, respectively. Our effective tax rate for GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest holders in the denominator of our effective tax rate computation.


Results of Operations – Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Summary
Net income attributable to HollyFrontier stockholders for the year ended December 31, 2012 was $1,727.2 million ($8.41 per basic and $8.38 per diluted share) a $703.8 million increase compared to $1,023.4 million ($6.46 per basic and $6.42 per diluted share) for the year ended December 31, 2011. Net income increased due principally to greater operating scale following our July 1, 2011 merger and higher refining margins in 2012. Refinery gross margins for the year ended December 31, 2012 increased to $24.89 per produced barrel compared to $20.64 for the year ended December 31, 2011.

Sales and Other Revenues
Sales and other revenues increased 30% from $15,439.5 million for the year ended December 31, 2011 to $20,090.7 million for the year ended December 31, 2012, due principally to the inclusion of sales volumes and related revenues attributable to the El Dorado and Cheyenne Refineries for a full year period and higher sales volumes of refined products produced from the legacy Holly refineries. Additionally, the average sales price we received per produced barrel sold increased 1% from $118.82 for the year ended December 31, 2011 to $119.48 for the year ended December 31, 2012. Sales and other revenues for the years ended December 31, 2012 and 2011, include $47.6 million and $46.4 million, respectively, in HEP revenues attributable to pipeline and transportation services provided to unaffiliated parties.

Cost of Products Sold
Cost of products sold increased 25% from $12,680.1 million for the year ended December 31, 2011 to $15,840.6 million for the year ended December 31, 2012, due principally to the inclusion of sales volumes and related cost of products sold at the El Dorado and Cheyenne Refineries, partially offset by lower crude oil costs for 2012. The average price we paid per barrel for crude oil and feedstocks and the transportation costs of moving the finished products to the market place decreased 4% from $98.18 for the year ended December 31, 2011 to $94.59 for the year ended December 31, 2012.

Gross Refinery Margins
Gross refining margin per produced barrel increased 21% from $20.64 for the year ended December 31, 2011 to $24.89 for the year ended December 31, 2012. This is due to the effects of a current year decrease in crude oil and feedstock prices along with slightly higher sales prices received on produced products sold. Gross refinery margin does not include the effects of depreciation or amortization.


39


Operating Expenses
Operating expenses, exclusive of depreciation and amortization increased 33% from $748.1 million for the year ended December 31, 2011 to $995.0 million for the year ended December 31, 2012, due principally to the inclusion of the legacy Frontier refinery operations for a full-year period and higher repair and maintenance and environmental remediation costs. In 2012, we increased certain environmental remediation accruals by $46.1 million to reflect revisions to certain cost estimates and the timeframe for which certain environmental remediation and monitoring activities are expected to occur. Also contributing to a much lesser extent were increased payroll costs attributable to the legacy Holly refining operations. For the years ended December 31, 2012 and 2011, operating expenses include $88.9 million and $61.1 million, respectively, in costs attributable to HEP operations.

General and Administrative Expenses
General and administrative expenses increased 7% from $120.1 million for the year ended December 31, 2011 to $128.1 million for the year ended December 31, 2012, due principally to higher employee benefit and equity-based compensation costs and increased corporate staffing levels as a result of our July 1, 2011 merger, net of the effects of merger related severance and integration costs incurred during 2011. For the years ended December 31, 2012 and 2011, general and administrative expenses include $5.3 million and $4.3 million, respectively, in costs attributable to HEP operations.

Depreciation and Amortization Expenses
Depreciation and amortization increased 52% from $159.7 million for the year ended December 31, 2011 to $242.9 million for the year ended December 31, 2012. The increase was due principally to depreciation and amortization attributable to the legacy Frontier refinery assets, capitalized improvement projects and HEP's UNEV Pipeline. For the years ended December 31, 2012 and 2011, depreciation and amortization expenses include $57.8 million and $33.3 million, respectively, in costs attributable to HEP operations.

Interest Income
Interest income for the year ended December 31, 2012 was $4.8 million compared to $1.3 million for the year ended December 31, 2011. This increase was due to interest received on our increased cash position and investments in marketable debt securities.

Interest Expense
Interest expense was $104.2 million for the year ended December 31, 2012 compared to $78.3 million for the year ended December 31, 2011. This increase principally reflects interest on the senior notes assumed upon our merger with Frontier. For the years ended December 31, 2012 and 2011, interest expense included $57.2 million and $38.2 million, respectively, in interest costs attributable to HEP operations.

Merger Transaction Costs
For the year ended December 31, 2011, we recognized merger transaction costs of $15.1 million related to our merger with Frontier on July 1, 2011. These costs included legal, advisory and other professional fees that were directly attributable to the merger. There were no such costs incurred for the year ended December 31, 2012.

Income Taxes
For the year ended December 31, 2012, we recorded income tax expense of $1,028.0 million compared to $582.0 million for the year ended December 31, 2011. This increase is due principally to significantly higher pre-tax earnings for the year ended December 31, 2012 compared to the same period of 2011. Our effective tax rates, before consideration of earnings attributable to the noncontrolling interest, were 36.9% and 35.5% for the years ended December 31, 2012 and 2011, respectively. Our effective tax rate for GAAP disclosure purposes reflects the inclusion of non-taxable earnings attributable to noncontrolling interest holders in the denominator of our effective tax rate computation.


LIQUIDITY AND CAPITAL RESOURCES

HollyFrontier Credit Agreement
We have a $1 billion senior secured credit agreement that matures in July 2016 (the “HollyFrontier Credit Agreement”) and may be used to fund working capital requirements, capital expenditures, acquisitions and general corporate purposes. Obligations under the HollyFrontier Credit Agreement are collateralized by our inventory, accounts receivables and certain deposit accounts and guaranteed by our material, wholly-owned subsidiaries. At December 31, 2013, we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $5.2 million under the HollyFrontier Credit Agreement.


40


HEP Credit Agreement
HEP has a $650 million senior secured revolving credit facility that matures 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. At December 31, 2013, HEP was in compliance with all of its covenants, had outstanding borrowings of $363.0 million and no outstanding letters of credit under the HEP Credit Agreement.

Indebtedness under the HEP Credit Agreement bears interest, at their 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 interest rates in effect on HEP’s Credit Agreement borrowings were 2.163% and 2.456% at December 31, 2013 and 2012, respectively.

HEP’s obligations under the HEP Credit Agreement are collateralized by substantially all of HEP’s assets (presented parenthetically in our consolidated balance sheets). Indebtedness under the HEP Credit Agreement involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. Any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no recourse to our other assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.

HollyFrontier Senior Notes
Our 6.875% senior notes ($150.0 million principal amount maturing November 2018) (the “HollyFrontier Senior Notes”) are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional debt, incur liens, enter into sale-and-leaseback transactions, pay dividends, enter into mergers, sell assets and enter into certain transactions with affiliates. Additionally, we have certain redemption rights under the HollyFrontier Senior Notes.

At any time, following notice to the trustee, that the HollyFrontier Senior Notes are rated investment grade by both Moody's and Standard & Poor's and no default or event of default exists, we are not subject to many of the foregoing covenants (a "Covenant Suspension"). As of December 31, 2013, the HollyFrontier Senior Notes were rated investment grade (BBB-) by Standard & Poor's and also investment grade (Baa3) by Moody's. As a result, we are under the Covenant Suspension pursuant to the terms of the indenture governing the HollyFrontier Senior Notes.

In June 2013, we redeemed our $286.8 million aggregate principal amount of 9.875% senior notes maturing June 2017.

HollyFrontier Financing Obligation
We have a financing obligation that relates to a sale and lease-back of certain crude oil tankage that we sold to an affiliate of Plains All American Pipeline, L.P. (“Plains”) in October 2009 for $40.0 million. Monthly lease payments are recorded as a reduction in principal over the 15-year lease term ending in 2024.

HEP Senior Notes
HEP’s senior notes consist of the following:

8.25% HEP senior notes ($150 million principal amount maturing March 2018)
6.5% HEP senior notes ($300 million principal amount maturing March 2020)

The 8.25% and 6.5% HEP senior notes (collectively, the “HEP Senior Notes”) are unsecured and impose certain restrictive covenants, including limitations on HEP’s ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. At any time when the HEP Senior Notes are rated investment grade by both Moody’s and Standard & Poor’s and no default or event of default exists, HEP will not be subject to many of the foregoing covenants. Additionally, HEP has certain redemption rights under the HEP Senior Notes. On February 12, 2014, HEP announced that it will redeem all of its outstanding 8.25% senior notes. The redemption price will be equal to 104.125% of the principal amount for a total payment to the holders of the notes of approximately $156.2 million plus accrued interest. The redemption of the 8.25% senior notes is scheduled to occur on March 15, 2014. HEP plans to fund the redemption with borrowings under the HEP Credit Agreement.

Indebtedness under the HEP Senior Notes involves recourse to HEP Logistics Holdings, L.P., its general partner, and is guaranteed by HEP’s wholly-owned subsidiaries. However, any recourse to the general partner would be limited to the extent of HEP Logistics Holdings, L.P.’s assets, which other than its investment in HEP, are not significant. HEP’s creditors have no other recourse to our assets. Furthermore, our creditors have no recourse to the assets of HEP and its consolidated subsidiaries.

41



HEP Common Unit Issuance
In March 2013, HEP closed on a public offering of 1,875,000 of its common units. Additionally, our wholly-owned subsidiary, HollyFrontier Holdings LLC, as a selling unitholder, closed on a public sale of 1,875,000 HEP common units held by it. HEP used net proceeds of $73.4 million to repay indebtedness incurred under its credit facility and for general partnership purposes.

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, 2013, our cash, cash equivalents and investments in marketable securities totaled $1.7 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.

We have a Board approved stock repurchase program that authorizes us to repurchase common stock in the open market or through privately negotiated transactions. The timing and amount of stock repurchases will depend on market conditions, corporate, regulatory and other relevant considerations. This program may be discontinued at any time by the Board of Directors. As of December 31, 2013, we had remaining authorization to repurchase up to $311.6 million under this stock repurchase program.

Cash and cash equivalents decreased $817.6 million for the year ended December 31, 2013. Net cash used for investing and financing activities of $526.7 million and $1,160.0 million, respectively, exceeded net cash provided by operating activities of $869.2 million. Working capital decreased by $593.9 million during the year ended December 31, 2013.

Cash Flows – Operating Activities

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Net cash flows provided by operating activities were $869.2 million for the year ended December 31, 2013 compared to $1,662.7 million for the year ended December 31, 2012, a decrease of $793.5 million. Net income for the year ended December 31, 2013 was $767.8 million, a decrease of $992.2 million compared to $1,760.0 million for the year ended December 31, 2012. Reconciling adjustments to net income consisted of depreciation and amortization, earnings of equity method investments, net of distributions, the write-off of an unamortized discount on the early extinguishment of debt, gain on sale of equity securities, deferred income taxes, equity-based compensation expense, fair value changes to derivative instruments and loss on settlement of retirement benefit obligations, net of contributions which totaled $430.4 million for the year ended December 31, 2013 compared to $410.7 million for the same period in 2012. Changes in working capital items decreased cash flows by $157.0 million for the year ended December 31, 2013 compared to $398.0 million for the year ended December 31, 2012. Additionally, for the year ended December 31, 2013, refinery turnaround expenditures increased to $193.9 million from $159.7 million for the same period of 2012.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Net cash flows provided by operating activities were $1,662.7 million for the year ended December 31, 2012 compared to $1,338.4 million for the year ended December 31, 2011, an increase of $324.3 million. Net income for the year ended December 31, 2012 was $1,760.0 million, an increase of $700.3 million compared to $1,059.7 million for the year ended December 31, 2011. Reconciling adjustments consisting of depreciation and amortization, earnings of equity method investments, net of distributions, gain on sale of equity securities, deferred income taxes, equity-based compensation expense, fair value changes to derivative instruments and loss on settlement of retirement benefit obligations, net of contributions resulted in an increase to operating cash flows of $433.0 million for the year ended December 31, 2012 compared to $182.3 million for the same period in 2011. Changes in working capital items decreased cash flows by $398.0 million for the year ended December 31, 2012 compared to an increase of $147.3 million for the year ended December 31, 2011. The decrease in working capital items for the year ended December 31, 2012 was due principally to higher inventory levels and a decrease in income taxes payable and accrued liabilities due to timing differences of payments during the fourth quarter of 2012 relative to 2011. Additionally, for the year ended December 31, 2012, refinery turnaround expenditures increased to $159.7 million from $32.0 million for the same period of 2011.


42


Cash Flows – Investing Activities and Planned Capital Expenditures

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Net cash flows used for investing activities were $526.7 million for the year ended December 31, 2013 compared to $711.1 million for the year ended December 31, 2012, a decrease of $184.4 million. Cash expenditures for properties, plants and equipment for 2013 increased to $425.1 million from $335.3 million for the same period in 2012. These include HEP capital expenditures of $51.9 million and $44.9 million for the years ended December 31, 2013 and 2012, respectively. In addition, for the year ended December 31, 2013, we received proceeds of $7.8 million from the sale of property and equipment, invested and advanced a net total of $8.7 million to Sabine Biofuels and acquired trucking operations for $11.3 million. For the year ended December 31, 2012, we invested $2.0 million in Sabine Biofuels. Also for the years ended December 31, 2013 and 2012, we invested $935.5 million and $671.6 million, respectively, in marketable securities and received proceeds of $846.1 million and $297.7 million, respectively, from the sale or maturity of marketable securities.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Net cash flows used for investing activities were $711.1 million for the year ended December 31, 2012 compared to net cash flows provided by investing activities of $228.5 million for the year ended December 31, 2011, a decrease of $939.6 million. Investing activities for 2011 reflect a net cash inflow due to an $872.7 million increase in cash and cash equivalents as a result of our July 1, 2011 merger with Frontier. Cash expenditures for properties, plants and equipment for 2012 decreased to $335.3 million from $374.2 million for the same period in 2011. These include HEP capital expenditures of $44.9 million and $216.2 million for the years ended December 31, 2012 and 2011, respectively, which include 2011 capital expenditures of $164.3 million to construct the UNEV Pipeline. Also for the years ended December 31, 2012 and 2011, we invested $2.0 million and $9.1 million, respectively, in Sabine Biofuels and $671.6 million and $561.9 million, respectively, in marketable securities and received proceeds of $297.7 million and $301.0 million, respectively, from the sale or maturity of marketable securities.


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. Our appropriated capital budget for 2014 is $185.0 million including both sustaining capital and major capital projects. We expect to spend approximately $400.0 million to $450.0 million in cash for capital projects appropriated in 2014 and prior years. In addition, we expect to spend $77.0 million on refinery turnarounds. Refinery turnaround spending is amortized over the useful life of the turnaround. Our new capital appropriation for 2014 and expected cash spending is as follows:

 
New Appropriation
 
Expected Cash Spending Range
 
(In millions)
Location:
 
 
 
 
 
El Dorado
$
43.0

 
$
85.0