10-K 1 a2016123110-k.htm 10-K Document


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 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, 2016
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission File No. 001-36550
________________________________________________________________________________________________________________________
PAR PACIFIC HOLDINGS, INC.
(Exact name of registrant as specified in its charter)
________________________________________________________________________________________________________________________
Delaware
84-1060803
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)
 
800 Gessner Road, Suite 875
 
Houston, Texas
77024
(Address of principal executive offices)
(Zip Code)
 
Registrant’s telephone number, including area code: (281) 899-4800
Securities registered under Section 12(b) of the Act:
Title of each class
 
Name of Exchange on which registered
Common stock, par value $0.01 per share
 
NYSE MKT LLC

Securities registered under to Section 12(g) of the Act: None


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  ý
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 Website, 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 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 smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
¨
 
Accelerated filer
ý
Non-accelerated filer
¨
(Do not check if a smaller reporting company)
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  ý
Indicate by check mark whether the registrant has filed all document and reports required to be filed by Sections 12, 13 or 15 (d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.    Yes  ý    No  ¨
The aggregate market value of voting common equity held by non-affiliates of the registrant was approximately $307,874,506 based on the closing sales price of the common stock on the NYSE MKT as of June 30, 2016. As of February 24, 2017, 45,538,261 shares of registrant’s Common Stock, $0.01 par value, were issued and outstanding.

Documents Incorporated By Reference
Certain information required to be disclosed in Part III of this report is incorporated by reference from the registrant's definitive proxy statement or an amendment to this report, which will be filed with the SEC not later than 120 days after the end of the fiscal year covered by this report.
 






TABLE OF CONTENTS
 
 
PAGE
PART I
 
 
Item 1. BUSINESS
Item 1A. RISK FACTORS
Item 1B. UNRESOLVED STAFF COMMENTS
Item 2. PROPERTIES
Item 3. LEGAL PROCEEDINGS
Item 4. MINE SAFETY DISCLOSURES
 
 
PART II
 
 
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Item 6. SELECTED FINANCIAL DATA
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Item 9A. CONTROLS AND PROCEDURES
Item 9B. OTHER INFORMATION
 
 
PART III
 
 
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 11. EXECUTIVE COMPENSATION
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
 
 
PART IV
 
 
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 16. FORM 10-K SUMMARY

i




Glossary of Selected Industry Terms
Unless otherwise noted or indicated by context, the following terms used in this Annual Report on Form 10- K have the following meanings:
barrel or bbl
A common unit of measure in the oil industry, which equates to 42 gallons.
blendstocks
Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others.
Brent
A light, sweet North Sea crude oil, characterized by an API gravity of 38 degrees and a sulfur content of approximately 0.4% by weight that is used as a benchmark for other crude oils.
cardlock
Automated unattended fueling sites that are open all day and are designed for commercial fleet vehicles.
catalyst
A substance that alters, accelerates or instigates chemical changes, but is not produced as a product of the refining process.
CO2
Carbon dioxide.
condensate
Light hydrocarbons which are in gas form underground, but are a liquid at normal temperatures and pressure.
crack spread
A simplified calculation that measures the difference between the price for light products and crude oil. For example, we reference the 4-1-2-1 crack spread, which is a general industry standard that approximates the per barrel refining margin resulting from processing four barrels of crude oil to produce one barrel of gasoline, two barrels of distillate (jet fuel and diesel) and one barrel of fuel oil.
distillates
Refers primarily to diesel, heating oil, kerosene and jet fuel.
ethanol
A clear, colorless, flammable oxygenated liquid. Ethanol is typically produced chemically from ethylene or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate.
feedstocks
Crude oil and partially refined petroleum products that are processed and blended into refined products.
GHG
Greenhouse gas.
jobber
A petroleum marketer.
LSFO
Low sulfur fuel oil.
Mbbls
Thousand barrels of crude oil or other liquid hydrocarbons.
Mbpd
Thousand barrels per day.
MMcf
Million cubic feet of natural gas.
MMcfd
Million cubic feet per day.
MMcfe
Million cubic feet equivalent which is determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil.
MMbtu
Million British thermal units.
MW
Megawatt.
NGL
Natural gas liquid.
NOx
Nitrogen oxides.
refined products
Petroleum products, such as gasoline, diesel and jet fuel, that are produced by a refinery.
throughput
The volume processed through a unit or refinery.
turnaround
A periodically required standard procedure to inspect, refurbish, repair and maintain a refinery. This process involves the shutdown and inspection of major processing units and typically occurs every three to five years.
single-point mooring
 Also known as a single buoy mooring, refers to a loading buoy that is anchored offshore and serves as an interconnect for tankers loading or offloading crude oil and refined products.
SO2
Sulfur dioxide.
WTI
West Texas Intermediate crude oil, a light, sweet crude oil, typically characterized by an API gravity between 38 degrees and 40 degrees and a sulfur content of approximately 0.3% by weight that is used as a benchmark for other crude oils.
yield
The percentage of refined products that is produced from crude oil and other feedstocks, net of fuel used as energy.

ii




PART I
 
Item  1. BUSINESS
 
OVERVIEW 
Par Pacific Holdings, Inc., based in Houston, Texas, owns, manages and maintains interests in energy and infrastructure businesses. Our strategy is to identify, acquire and operate energy and infrastructure companies with attractive competitive positions. We were created through the successful reorganization of Delta Petroleum Corporation ("Delta") in August 2012. The reorganization converted approximately $265 million of unsecured debt to equity and allowed us to preserve significant tax attributes. We changed our name from Par Petroleum Corporation to Par Pacific Holdings, Inc. effective October 20, 2015.
Our business is organized into three primary operating segments:
1) Refining - Our refinery in Kapolei, Hawaii, produces ultra-low sulfur diesel, gasoline, jet fuel, marine fuel and other associated refined products primarily for consumption in Hawaii. Our refinery in Newcastle, Wyoming, produces gasoline, ultra-low sulfur diesel, jet fuel and other associated refined products that are primarily marketed in Wyoming and South Dakota.
2) Retail - Our retail outlets sell gasoline, diesel and retail merchandise throughout the islands of Oahu, Maui, Hawaii and Kauai. Our retail network includes Hele, Tesoro and "76" branded retail sites, cardlock stations, company-operated convenience stores, sites operated in cooperation with 7-Eleven and other sites operated by third parties. We recently completed the rebranding of 32 out of 90 fueling stations in Hawaii to Hele, a new proprietary brand.
3) Logistics - We own and operate terminals, pipelines, a single-point mooring ("SPM") and trucking operations to distribute refined products throughout the island of Oahu as well as the neighboring islands of Maui, Hawaii, Molokai and Kauai. We own and operate a crude oil pipeline gathering system and related storage facilities in Wyoming and a refined products pipeline that transports product from our Wyoming refinery to a common carrier with access to Rapid City, South Dakota. Our Wyoming operations include storage, loading racks and a rail siding at the refinery site. We also own and operate a jet fuel storage facility and pipeline that serve Ellsworth Air Force Base in South Dakota.
We own an equity investment in Laramie Energy, LLC ("Laramie Energy," formerly known as Piceance Energy, LLC), a joint venture entity focused on producing natural gas in Garfield, Mesa and Rio Blanco Counties, Colorado. On December 17, 2015, we entered into an equity commitment letter with Laramie Energy, pursuant to which we agreed to purchase certain membership interests of Laramie Energy for an aggregate cash purchase price of $55.0 million, subject to certain financing commitments by various lenders and additional equity investors, in connection with the closing of a purchase and sale agreement whereby Laramie Energy agreed to acquire certain properties in the Piceance Basin for $157.5 million, subject to customary purchase price adjustments. The transaction closed on March 1, 2016, and, upon the closing of the transaction, Laramie Energy assumed ownership and operatorship of the purchased properties and our ownership interest in Laramie Energy increased from 32.4% to 42.3%.
The refining, retail and logistics segments were established through the acquisition of Par Hawaii Refining, LLC ("PHR," formerly Hawaii Independent Energy, LLC) from Tesoro Corporation ("Tesoro") on September 25, 2013 for approximately $75 million in cash, plus net working capital and inventories, certain contingent earn-out payments of up to $40 million and the funding of certain start-up expenses and overhaul costs prior to closing. During 2014, we successfully completed the integration of PHR, terminated a transition services agreement with Tesoro and greatly reduced our reliance on third-party service providers in operating our business. The contingent earn-out payments are calculated annually for each of the years ended 2014, 2015 and 2016 with an annual cap of $20 million. During 2016, we paid Tesoro a total of $16.8 million to settle the 2014 and 2015 earn-out payments.
On April 1, 2015, we completed the acquisition of Par Hawaii, Inc. ("PHI," formerly Koko’oha Investments, Inc.), a Hawaii corporation that owns 100% of the outstanding membership interests of Mid Pac Petroleum, LLC (“Mid Pac”), for cash consideration of approximately $74.4 million and the assumption of $45.3 million of debt. The results of operations of Mid Pac are included in our segments effective April 1, 2015. In conjunction with the acquisition, we also obtained the exclusive rights to the "76" brand in Hawaii through 2024.
On June 14, 2016, we entered into a unit purchase agreement (the “Purchase Agreement”) with Black Elk Refining, LLC to purchase all of the issued and outstanding units representing the membership interests in Hermes Consolidated, LLC (d/b/a Wyoming Refining Company) and indirectly Wyoming Refining Company’s wholly owned subsidiary, Wyoming Pipeline Company, LLC (collectively, “Wyoming Refining” or "WRC") (the "WRC Acquisition"). Wyoming Refining owns and operates an 18 thousand barrels per day refinery and related logistics assets in Newcastle, Wyoming. We completed the WRC Acquisition

1




on July 14, 2016, for cash consideration of $209.4 million, including a deposit of $5.0 million paid in June 2016 and assumed debt consisting of term loans of $58.0 million and revolving loans of $10.1 million. The results of operations of Wyoming Refining are included in our refining and logistics segments effective July 14, 2016.
In addition to the three operating segments described above, we have two additional reportable segments: (i) Texadian and (ii) Corporate and Other. Texadian focuses on sourcing, marketing, transporting and distributing crude oil and refined products in the U.S. and Canada. Corporate and Other includes administrative costs and several small non-operated oil and gas interests that were owned by our predecessor. Please read Note 19—Segment Information to our consolidated financial statements under Item 8 of this Form 10-K for detailed information on our operating results by segment.
Corporate Information    
Our common stock is listed and trades on the NYSE MKT under the ticker symbol “PARR.” Our principal executive office is located at 800 Gessner Road, Suite 875, Houston, Texas 77024 and our telephone number is (281) 899-4800. Throughout this Annual Report on Form 10-K, the terms “Par,” “the Company,” “we,” “our,” and “us” refer to Par Pacific Holdings, Inc. and its consolidated subsidiaries unless the context suggests otherwise.
Available Information
Our website address is www.parpacific.com. Information contained on our website is not part of this Annual Report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any other materials filed with (or furnished to) the U.S. Securities and Exchange Commission ("SEC") by us are available on our website (under “Investors”) free of charge, as soon as reasonably practicable after such reports are filed with or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s website at http://www.sec.gov.
OPERATING SEGMENTS
Refining
Our refining segment buys and refines crude oil and other feedstocks into petroleum products (such as gasoline and distillates) at our Hawaii and Wyoming refineries.
Hawaii Refinery
Our Hawaii refinery is located in Kapolei, Hawaii, on the island of Oahu on approximately 130 fee-owned acres about 20 miles west of Honolulu and is rated at 94 thousand barrels per day throughput. We source our crude oil for the Hawaii refinery from North America, South America, Southeast Asia, the Middle East, Russia and other sources. The Hawaii refinery's major processing units include crude distillation, vacuum distillation, visbreaking, hydrocracking, naphtha hydrotreating and reforming units, which produce ultra-low sulfur diesel, gasoline, jet fuel, marine fuel, LSFO and other associated refined products. We believe the configuration of our Hawaii refinery uniquely meets the demands of the Hawaii market.
Crude oil is transported to Hawaii in tankers then discharged through our SPM. Our three underwater pipelines from the SPM allow crude oil and refined products to be transferred to and from the Hawaii refinery.
Crude oil is received into the Hawaii refinery tank farm, which includes 2.4 million barrels of total crude oil storage. Following crude oil receipt, we process the crude oil through the various refining units into products and store them in the Hawaii refinery’s 2.5 million barrels of refined product tankage. The Hawaii refinery storage capacity allows us to manage the various product requirements of the state of Hawaii.
We have Supply and Offtake Agreements with J. Aron & Company ("J. Aron") that allows us to finance our Hawaii refinery hydrocarbon inventories. Under the Supply and Offtake Agreements, J. Aron holds title to all crude oil and refined product stored in tankage at the Hawaii refinery. We purchase crude oil from J. Aron on a daily basis at market prices and sell refined products to J. Aron as they are produced. We repurchase these refined products from J. Aron prior to selling them to third parties.

2




Set forth below are summaries of the capacity of our Hawaii refinery:
            
Hawaii Refining Unit
 
Capacity (Mbpd)
Crude Unit
 
94
Vacuum Distillation Unit
 
40
Hydrocracker
 
18
Catalytic Reformer
 
13
Visbreaker
 
11
Naphtha Hydrotreater
 
13
            
Hawaii Refining Unit
 
Capacity
Hydrogen Plant (MMcfd)
 
18
Co-generation Turbine Unit (MW)
 
20
The Hawaii refinery operated at an average throughput of 70.2 thousand barrels per day, or 75% utilization, for the year ended December 31, 2016. Below is a summary of our throughput percentage by type of crude oil and the product yield percentage for the years ended December 31, 2016, 2015 and 2014:
 
Year Ended December 31,

2016

2015

2014
 
 
 
 
 
 
Feedstocks throughput (Mbpd)
70.2

 
77.3

 
68.2

Source of crude oil:

 
 
 
 
North America
41.7
%
 
47.7
%
 
48.8
%
Asia
30.0
%
 
33.0
%
 
1.3
%
Africa
13.7
%
 
8.3
%
 
3.7
%
Latin America
3.9
%
 
8.0
%
 
23.4
%
Middle East
10.7
%
 
2.1
%
 
22.8
%
Europe
%
 
0.9
%
 
%
Total
100.0
%
 
100.0
%
 
100.0
%



 


 


Yield (% of total throughput):
 
 
 
 
 
Gasoline and gasoline blendstocks
26.8
%
 
26.2
%
 
24.5
%
Distillates
44.7
%
 
44.1
%
 
38.9
%
Fuel oils
20.1
%
 
22.0
%
 
30.7
%
Other products
4.8
%
 
4.7
%
 
2.9
%
Total yield
96.4
%
 
97.0
%
 
97.0
%
Our Hawaii refining business sells refined products through our logistics network to wholesale and bulk customers and to our retail business in Hawaii. Wholesale customers include jobbers and other non-end users, as well as 37 fueling stations where operations and consumer pricing are controlled by third parties. Bulk customers include utilities, military bases, marine vessels, industrial end-users and exports.
The profitability of our Hawaii refining business is heavily influenced by crack spreads in both the Singapore and U.S. West Coast markets. These markets reflect the closest, liquid market alternatives to source refined products for Hawaii. We believe the Singapore 4-1-2-1 and Mid Pacific 4-1-2-1 crack spreads (or four barrels of Brent converted into one barrel of gasoline, two barrels of distillate (jet fuel and diesel) and one barrel of fuel oil) best reflect a market indicator for our Hawaii refining operations. During the course of 2016, both markets exhibited significant volatility with lows reached during the late second and early third quarters. The Singapore 4-1-2-1 crack spread averaged $3.74 per barrel during 2016 with a low of $2.46 per barrel in the second quarter and a high of $6.03 per barrel in the fourth quarter. The Mid Pacific 4-1-2-1 crack spread averaged $4.96 per barrel during 2016 with a low of $3.96 per barrel in the second quarter and a high of $7.00 per barrel in the fourth quarter.

3




Below is a summary of average crack spreads for the years ended December 31, 2016, 2015 and 2014:
 
Year Ended December 31,
 
2016
 
2015
 
2014
4-1-2-1 Mid Pacific Crack Spread (1)
$
4.96

 
$
8.31

 
$
7.16

4-1-2-1 Singapore Crack Spread
3.74

 
6.88

 
6.25

_______________________________________________________
(1)
Calculated using a ratio of 80% Singapore and 20% San Francisco indexes.
During a declining crude oil market, we tend to benefit from expanding crack spreads as our product portfolio pricing terms tend to lag our crude oil pricing terms ("pricing lag effect"). A significant portion of our contracts typically price at least one week in arrears and some of our utility customer contracts have at least a one month lag in the pricing terms. During the fourth quarter of 2015, we began economically hedging the pricing lag effect.
Wyoming Refinery
Our Wyoming refinery is located in Newcastle, Wyoming, and is rated at 18 thousand barrels per day throughput. We source our crude oil for this refinery from North America. The Wyoming refinery's major processing units include crude distillation, catalytic cracker, naphtha hydrotreating and reforming units, which produce gasoline, ultra-low sulfur diesel, jet fuel and other associated refined products.
Set forth below is a summary of the capacity of our Wyoming refinery:
            
Wyoming Refining Unit
 
Capacity (Mbpd)
Crude Unit
 
18
Residual Fluid Catalytic Cracker
 
7
Catalytic Reformer
 
3
Alkylation
 
1
Naphtha Hydrotreater
 
3
Diesel Hydrotreater
 
6
Isomerization
 
4
The Wyoming refinery operated at an average throughput of 15.8 thousand barrels per day, or 88% utilization, for the period from July 14, 2016 to December 31, 2016. Below is a summary of our product yield percentage for the period from July 14, 2016 to December 31, 2016:
Yield (% of total throughput):
 
Gasoline and gasoline blendstocks
56.0
%
Distillate
39.3
%
Fuel oil
1.9
%
Other products
1.0
%
Total yield
98.2
%

Our Wyoming refining business sells refined products through our logistics network to wholesale, bulk and retail customers primarily in the Rapid City, South Dakota, area.    
The profitability of our Wyoming refinery is heavily influenced by crack spreads in nearby markets. We believe the Wyoming 3-2-1 Index is the best market indicator for our operations in Wyoming. The Wyoming 3-2-1 Index is computed by taking two parts gasoline and one part distillate (ultra-low sulfur diesel) as created from three barrels of West Texas Intermediate Crude. Pricing is based 50% on applicable product pricing in Rapid City, South Dakota, and 50% on applicable product pricing in Denver, Colorado. The Wyoming 3-2-1 Index averaged $16.27 per barrel during the period from July 14, 2016 to December 31, 2016.



4




Competition
All facets of the energy industry are highly competitive. Our competitors include major integrated, national and independent energy companies. Many of these competitors have greater financial and technical resources and staff which may allow them to better withstand and react to changing and adverse market conditions.
Our refining business sources and obtains all of our crude oil from third-party sources and competes globally for crude oil and feedstocks. Our Hawaii refinery, through our facility with J. Aron, has access to a large variety of markets for crude oil imports and product exports. Our Wyoming refinery sources its crude oil and feedstocks primarily from the Petroleum Administration for Defense District IV Rocky Mountain ("PADD IV") region of the United States. Please read “Item 7. — Management's Discussion and Analysis of Financial Condition and Results of Operations — Commitments and Contingencies — Supply and Offtake Agreements” of this Form 10-K for further information.
Our refined product sales from our Hawaii refinery, outside the Hawaii market, typically target the Eastern Asia and U.S. West Coast markets. Our Wyoming refinery primarily sells refined products locally in the PADD IV region.
Retail
The retail segment includes 90 locations in Hawaii where we set the price to the retail consumer. Of these 90 locations, 37 are outlets operated by our personnel and include various sizes of kiosks, snack shops or convenience stores. The remaining 53 locations are cardlocks or sites operated by third parties where we retain ownership of the fuel and set retail pricing.
We hold exclusive licenses within the state of Hawaii to utilize both the Tesoro and the “76” brands for retail locations. We recently completed the rebranding of 32 out of 90 fueling stations in Hawaii to Hele, a new proprietary brand. All of the manned locations (and one cardlock) are currently operated under one of those brands (see chart below). The term of the Tesoro license expires in September 2017, whereupon we anticipate rebranding additional fueling stations to the Hele brand. The “76” license agreement expires September 24, 2024, unless extended by mutual agreement.
The following table shows our owned and leased retail outlets by location and type:
Location and Channel of Trade
 
"76" Brand
 
Tesoro Brand
 
Hele Brand
 
Unbranded
 
Total
Oahu
 
 
 
 
 
 
 
 
 
 
Company operated
 
1

 
2

 
17

 

 
20

7-Eleven alliance
 
22

 
1

 
5

 

 
28

Fee operated
 
5

 

 
3

 

 
8

Cardlock
 

 

 
1

 
3

 
4

Oahu total
 
28

 
3

 
26

 
3

 
60

Big Island
 


 


 
 
 


 


Company operated
 
3

 

 
6

 

 
9

Fee operated
 
3

 

 

 

 
3

Big Island total
 
6

 

 
6

 

 
12

Maui
 


 


 
 
 


 


Company operated
 
2

 
3

 

 

 
5

Fee operated
 
2

 

 

 

 
2

Maui total
 
4

 
3

 

 

 
7

Kauai
 


 


 
 
 


 


Company operated
 
3

 

 

 

 
3

Cardlock
 

 

 

 
8

 
8

Kauai total
 
3

 

 

 
8

 
11

Total for all locations
 
41

 
6

 
32

 
11

 
90


5




Competition
Competitive factors that affect our retail performance include product price, station appearance, location, customer service and brand awareness. Our competitors include the Chevron, Shell, Texaco, Costco, Safeway and Sam's Club national brands, a regional brand Aloha and other local retailers.  
Logistics
Our logistics segment generates revenues by charging fees for transporting crude oil to our refineries, delivering refined products to wholesale and bulk customers and to our retail business and storing crude oil and refined products. Substantially all of our revenues from our logistics segment represent intercompany transactions that are eliminated in consolidation.

Hawaii Logistics
    
Our logistics network extends throughout the state of Hawaii. On Oahu, the system begins with our SPM located 1.7 miles offshore of our Hawaii refinery. This SPM allows for the safe, reliable and efficient receipt of crude oil shipments to the Hawaii refinery, as well as both the receipt and export of finished products. Connecting the SPM to the Hawaii refinery are three undersea pipelines: a 30-inch line for crude oil, a 20-inch line and a 16-inch line, both for the import or export of refined products. From the Hawaii refinery gate, we distribute refined products through our logistics network throughout the island of Oahu, as well as the neighboring islands of Maui, Hawaii, Molokai and Kauai and for export to the U.S. West Coast and Asia.

The Oahu logistics network includes a 27-mile wholly owned and operated pipeline network that transports refined products from our Hawaii refinery to delivery locations. The majority of our Oahu refined product volumes are distributed through the Honolulu Products Pipeline to (i) our leased and operated Sand Island terminal, (ii) the Honolulu International Airport, (iii) interconnections to Navy and Air Force fuel facilities and (iv) a third-party terminal in Honolulu Harbor. In addition to the Honolulu Products Pipeline, we own four proprietary pipelines connecting our Hawaii refinery to Kalaeloa Barbers Point Harbor, approximately three miles from the Hawaii refinery. The four pipelines deliver refined products to barges for distribution to the neighboring islands or export, as well as interconnecting with the other local Hawaii refinery, the local utility pipeline and storage network and another third-party terminal on the west side of Oahu. The Oahu pipeline network is generally configured to be bidirectional, allowing for both delivery and receipt of products.
Our terminal facilities on Oahu include our Sand Island facility that comprises two tanks with a total capacity of 30 thousand barrels, as well as contractual rights to utilize strategically located third-party facilities both near the Hawaii refinery and at Honolulu Harbor near downtown.
We also operate a proprietary trucking business on Oahu to distribute gasoline and road diesel to the final point of sale.
Our logistics network for the neighboring islands consists of leased barge equipment and refined product tankage and proprietary trucking operations on the islands of Maui, Hawaii, Molokai and Kauai. Specifically, we charter two barges to serve our neighbor island markets. This includes the Nale with 86 thousand barrels of capacity and the Ne’ena with 50 thousand barrels of capacity. In addition to neighbor island deliveries, the Ne’ena is utilized to service our bunker fuel customers, such as passenger cruise ships and container vessels. We also lease the barge Capella primarily for the import of ethanol from the U.S. West Coast with periodic backhauls of refined products for sale in the Pacific Northwest.
The barges deliver to and product is dispensed from a neighbor island network of eight petroleum terminals with total capacity of 301 thousand barrels.
Wyoming Logistics
Our Wyoming logistics network includes a 140-mile crude oil pipeline gathering system that provides us access to crude oil from the Powder River Basin. Our Wyoming logistics network also includes a 40-mile refined products pipeline that transports product from our Wyoming refinery to a common carrier with access to Rapid City, South Dakota. 
The logistics network in Wyoming includes storage, loading racks and a rail siding at the refinery site. Our crude oil and refined product tanks at the Wyoming refinery have a total capacity of 470 thousand barrels. We also own and operate a jet fuel storage facility and pipeline that serve Ellsworth Air Force Base in South Dakota.
Hawaii Market
The Hawaii economy continues to grow. The Hawaii State Department of Business, Economic Development and Tourism (“DBEDT”) reported a population increase of 2% from 2014 to 2016. Real personal income is projected by DBEDT to grow by 3% in 2017. The number of visitors increased by 7% from 2014 to 2016 and continued growth is forecasted.

6




Demand for jet fuel is somewhat higher in Hawaii during the winter months than during the summer months as tourism increases. Refining margins remain volatile and our results of operations may not reflect these historical seasonal trends.
Wyoming and South Dakota Markets
The primary market for our Wyoming refining products is the Pennington County, South Dakota, area which includes Rapid City.  According to the U.S. Census Bureau, the population in Pennington County increased by an annual rate of 8% from 2010 to 2015.  Demand for gasoline is highly seasonal, with a large increase in demand during the summer driving season.  The local economy is anchored by tourism, including visitors to Mount Rushmore and the Black Hills, as well as government and healthcare spending. Historically, the unemployment rate in Pennington County has remained significantly below the national rate.  We also distribute refined products to customers in central and northeastern Wyoming.  The economy in Wyoming is sensitive to demand for Powder River Basin coal and other locally-produced commodities.
OTHER OPERATIONS
Laramie Energy
We own an equity investment in Laramie Energy as a result of the contribution of certain natural gas and oil interests to a partnership with Laramie Energy II, LLC ("Laramie") in conjunction with our corporate reorganization in August 2012 and cash contributions made in 2015 and 2016.
Laramie Energy's operations and assets are located in Garfield, Mesa and Rio Blanco Counties, Colorado. On March 1, 2016, Laramie Energy acquired certain properties in the Piceance Basin for $157.5 million. The acquired properties consist of approximately 249 billion cubic feet equivalent of proved developed producing reserves as of December 31, 2016, more than 53,000 net operated acres and more than 18,000 net non-operated acres. The acquired and existing properties produce primarily from the Mesaverde Formation and, to a lesser extent, the Mancos Formation. The majority of the acquired acreage is adjacent to Laramie Energy's existing assets.
As of December 31, 2016, the estimated proved reserves of Laramie Energy and the estimated proved reserves we own indirectly through Laramie Energy are the following: 
 
Natural
Gas
(MMcf)
 
Oil
(Mbbls)
 
NGLs
(Mbbls)
 
Total
(MMcfe) (1)
Laramie Energy:
 
 
 
 
 
 
 
Proved developed
377,069

 
1,219

 
10,281

 
446,069

Proved undeveloped
393,399

 
1,202

 
11,046

 
466,884

Total
770,468


2,421

 
21,327

 
912,953

Company's share of Laramie Energy;
 
 
 
 
 
 
 
Proved developed
159,500

 
516

 
4,349

 
188,690

Proved undeveloped
166,408

 
508

 
4,672

 
197,488

Total
325,908

 
1,024

 
9,021

 
386,178

________________________________________________
(1)
MMcfe is computed using a ratio of 6 Mcf of natural gas to 1 barrel of oil or NGL.
For more information regarding our proved undeveloped reserves, please read "Item 2. — Properties — Reserves — Proved Undeveloped Reserves" of this Form 10-K.

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The following table presents the estimated future net cash flows related to proved developed producing, proved developed non-producing and proved undeveloped reserves that we own indirectly through Laramie Energy as of December 31, 2016 (in thousands): 
 
Proved
Developed
Producing
 
Proved
Developed
Non-producing
 
Proved
Undeveloped
 
Total (1)
Estimated future undiscounted net cash flows
$
173,653

 
$
2,523

 
$
141,228

 
$
317,404

Standardized measure of discounted future net cash flows
107,812

 
239

 
34,842

 
142,893

 
________________________________________________
(1)
Prices are based on the historical first-day-of-the-month twelve-month average posted price depending on the area. These prices are adjusted for quality, energy content, regional price differentials and transportation fees. All prices are held constant throughout the lives of the properties. The average adjusted product prices are $38.73 per barrel of crude oil, $14.49 per barrel of natural gas liquids and $2.41 per Mcf of natural gas.
Reconciliation of Standardized Measure to PV-10
PV-10 is the estimated present value of the future net revenues calculated based on our estimated proved reserves before income taxes discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. This measure should not be considered a substitute for, or superior to, measures prepared in accordance with U.S. generally accepted accounting principles ("GAAP"). We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our natural gas and oil properties to other companies and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. 
The following table provides a reconciliation of the standardized measure of discounted future net cash flows to PV-10 at December 31, 2016 (in thousands): 
 
 
Company's 
Share
of Laramie
Energy
Standardized measure of discounted future net cash flows
 
$
142,893

Present value of future income taxes discounted at 10% (1)
 

PV-10
 
$
142,893

________________________________________________
(1)
There is no present value of future income taxes as we believe we have sufficient net operating loss carryforwards to offset any income. Please read Note 18—Income Taxes to our consolidated financial statements under Item 8 of this Form 10-K for further information.
For more information on our natural gas and oil operations, please read “Item 2. — Properties” of this Form 10-K.
Other non-operated oil and gas interests
We own other non-operated positions in producing and non-producing natural gas and oil interests and undeveloped leasehold interests and related assets in Colorado and New Mexico. As of December 31, 2016, our estimated proved reserves related to other non-operated natural gas and oil interests of 420 MMcfe represented less than 1% of our total proved reserves owned indirectly through Laramie Energy of 386,178 MMcfe. Please read Note 22—Supplemental Oil and Gas Disclosures (Unaudited) to our consolidated financial statements under Item 8 of this Form 10-K for further information on our proved reserves related to other non-operated natural gas and oil interests.
Through our non-operated working interests, we have natural gas and oil leases with governmental entities and other third parties who enter into natural gas and oil leases or assignments with us in the regular course of our business.

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Competition
The natural gas and oil business is highly competitive. The principal markets for natural gas and oil are refineries and transmission companies that have facilities near Laramie Energy's producing properties. Natural gas and oil produced from Laramie Energy's wells are normally sold to various purchasers. Natural gas wells are connected to pipelines generally owned by the natural gas purchasers. A variety of pipeline transportation charges are usually included in the calculation of the price paid for the natural gas. Crude oil is picked up and transported by the purchaser from the wellhead. In some instances, Laramie Energy is charged a fee for the cost of transporting the crude oil, which is deducted from or accounted for in the price paid for the crude oil.
Texadian
We operate an integrated sourcing, marketing, transportation and distribution business focused on energy commodities, principally crude oil. We use a variety of transportation modes, which are generally leased, to transport products, including pipelines. We also lease a fleet of approximately 150 railcars. We purchase and resell crude oil primarily from the Western U.S. and Canada to customers in the Midwest, U.S. Gulf Coast and East Coast regions of the U.S. The principal asset of the Texadian business is its historical shipper status on lines moving Canadian crude oil to the U.S. 
Texadian is a commodity-driven business with numerous industry participants. Our competitors include terminal companies, major integrated oil and gas companies and their affiliates, wholesalers and independent marketers. Our success is dependent on pricing and margins dictated by the global supply and demand of commodities. As of December 31, 2016, Texadian has ceased its business operations other than maintaining its fleet of railcars and its historical shipper status.
BANKRUPTCY AND PLAN OF REORGANIZATION
Background and Plan Approval
In 2011 and 2012, Delta and its subsidiaries ("Debtors") filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware ("Bankruptcy Court"). In March 2012, the Debtors obtained approval from the Bankruptcy Court to proceed with Laramie as the sponsor of a plan of reorganization (“Plan”). In June 2012, Delta entered into a contribution agreement (“Contribution Agreement”) with a new joint venture formed by Delta, Laramie and Laramie Energy to effect the transactions contemplated by the Plan. On August 31, 2012 ("Emergence Date"), Delta emerged from bankruptcy, amended and restated its certificate of incorporation and bylaws, changed its name to Par Petroleum Corporation and contributed the majority of its natural gas and oil properties to Laramie Energy.
General Recovery Trust
On the Emergence Date, the Delta Petroleum General Recovery Trust (“General Trust”) was formed to pursue certain litigation against third parties or causes of action under the U.S. Bankruptcy Code and other claims and potential claims that the Debtors hold against third parties. The General Trust was funded with $1.0 million pursuant to the Plan.
The General Trust is pursuing all bankruptcy causes of action, claim objections and resolutions and is responsible for winding up the bankruptcy. The General Trust is overseen by a three-person General Trust Oversight Board and our General Counsel is currently the trustee (“Recovery Trustee”). Costs, expenses and obligations incurred by the General Trust are charged against assets of the General Trust. To conduct its operations and fulfill its responsibilities under the Plan and the trust agreements, the Recovery Trustee may request additional funding from us. Any litigation pending at the time we emerged from Chapter 11 was transferred to the General Trust for resolution and settlement in accordance with the Plan and the order confirming the Plan. We are the beneficiary of the General Trust, subject to the terms of the trust agreement and the Plan. Since the Emergence Date, the General Trust has filed various claims and causes of action against third parties before the Bankruptcy Court, which actions are ongoing. Upon liquidation of the various claims and causes of action held by the General Trust, the proceeds, less certain administrative reserves and expenses, will be transferred to us. It is unknown at this time what proceeds, if any, we will realize from the General Trust’s litigation efforts.     
Through December 31, 2013, the General Trust released approximately $5.2 million to us, which was available for our general use, due to a negotiated reduction in certain fees and claims associated with the bankruptcy, as well as a favorable variance in actual expenses versus budgeted expenses. No funds were released during the years ended December 31, 2016, 2015 and 2014.

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Shares Reserved for Unsecured Claims
The Plan provides that certain allowed general unsecured claims be paid with shares of our common stock. On the Emergence Date, 112 claims totaling approximately $73.7 million had been filed in the bankruptcy. Pursuant to the Plan, between the Emergence Date and December 31, 2013, the Recovery Trustee settled 84 claims with an aggregate face amount of $33.5 million for approximately $5.7 million in cash and 228,735 shares of common stock. Pursuant to the Plan, during the year ended December 31, 2014, the Recovery Trustee settled one additional claim with an aggregate face amount of $3.7 million for approximately 146 thousand shares of common stock. Pursuant to the Plan, during the year ended December 31, 2015, the Recovery Trustee settled one additional claim with an aggregate face amount of approximately $31 thousand for 1,674 shares of common stock. Pursuant to the Plan, during the year ended December 31, 2016, the Recovery Trustee settled six additional claims for aggregate consideration of approximately $0.7 million.
As of December 31, 2016, two related claims totaling approximately $22.4 million remained to be resolved by the Recovery Trustee. One of the two remaining claims was filed by the U.S. Government for approximately $22.4 million relating to ongoing litigation concerning a plugging and abandonment obligation in Pacific Outer Continental Shelf Lease OCS-P 0320, comprising part of the Sword Unit in the Santa Barbara Channel, California. The second unliquidated claim, which is related to the same plugging and abandonment obligation, was filed by Noble Energy Inc., the operator and majority interest owner of the Sword Unit. We believe the probability of issuing stock to satisfy the full claim amount is remote, as the obligations upon which such proof of claim is asserted are joint and several among all working interest owners and Delta, our predecessor, only owned an approximate 3.4% aggregate working interest in the unit.
              The settlement of claims is subject to ongoing litigation and we are unable to predict with certainty how many shares will be required to satisfy all claims. Pursuant to the Plan, allowed claims are settled at a ratio of 54.4 shares per $1,000 of claim. We have reserved approximately $0.5 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at December 31, 2016. Please read “Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commitments and Contingencies – Bankruptcy Matters” of this Form 10-K for further information.
ENVIRONMENTAL REGULATIONS
General 
Our activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, regulations and rules regulating the release of materials in the environment or otherwise relating to the protection of human health, safety and the environment will not have a material effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot predict what effect additional regulation or legislation, enforcement policies and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities. 
Periodically, we receive communications from various federal, state and local governmental authorities asserting violations of environmental laws and/or regulations. These governmental entities may also propose or assess fines or require corrective actions for these asserted violations. We intend to respond in a timely manner to all such communications and to take appropriate corrective action. We do not anticipate that any such matters currently asserted will have a material impact on our financial condition, results of operations or cash flows. 
Refining activities
Like other petroleum refiners, our operations are subject to extensive and periodically changing federal and state environmental regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities. Many of these regulations are becoming increasingly stringent and the cost of compliance can be expected to increase over time. Our policy is to accrue environmental and clean-up related costs of a non-capital nature when it is probable that a liability has been incurred and the amount can be reasonably estimated. Such estimates may be subject to revision in the future as regulations and other conditions change. 
Natural gas and oil production
Our activities with respect to exploration and production of natural gas and oil, including the drilling of wells and the operation and construction of pipelines, plants and other facilities for extracting, transporting, processing, treating or storing natural gas, crude oil and other petroleum products, are subject to stringent environmental regulation by state and federal authorities,

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including the U.S. Environmental Protection Agency ("EPA"). Such regulation can increase the costs of planning, designing, installing and operating such facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities are inherent in natural gas and oil production, transport and storage operations and there can be no assurance that significant costs and liabilities will not be incurred. Moreover it is possible that other developments, such as spills or other unanticipated releases, stricter environmental laws and regulations and claims for damages to property or persons resulting from oil and gas production, transport or storage would result in substantial costs and liabilities to us. In California, our activities are subject to an additional level of state environmental review. 
Climate Change and Regulation of Greenhouse Gases 
According to certain scientific studies, emissions of CO2, methane, nitrous oxide and other gases commonly known as GHG may be contributing to global warming of the earth’s atmosphere and to global climate change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act ("CAA") definition of an “air pollutant”. In response, the EPA promulgated an endangerment finding, paving the way for regulation of GHG emissions under the CAA. The EPA has now begun regulating GHG under the CAA. New construction or material expansions that meet certain GHG emissions thresholds will likely require that, among other things, a GHG permit be issued in accordance with the CAA regulations and we will be required in connection with such permitting to undertake a technology review to determine appropriate controls to be implemented with the project in order to reduce GHG emissions. As currently written and based on current company operations, however, our natural gas and oil exploration and production activities and our existing refining activities are not subject to federal GHG permitting requirements.
Furthermore, the EPA is currently developing refinery-specific GHG regulations and performance standards that are expected to impose GHG emission limits and/or technology requirements. These control requirements may affect a wide range of refinery operations. Any such controls could result in material increased compliance costs, additional operating restrictions for our business and an increase in cost of the products we produce, which could have a material adverse effect on our financial position, results of operations and liquidity. We believe the change of Administration, however, makes it unlikely that such additional GHG requirements will be finalized in the near term.
The EPA has also promulgated rules requiring large sources to report their GHG emissions. Reports are being made in connection with our refining business. Sources subject to these reporting requirements also include on and offshore petroleum and natural gas production and onshore natural gas processing and distribution facilities that emit 25,000 metric tons or more of CO2 equivalent per year in aggregate emissions from all site sources. To date, our natural gas and oil exploration and production activities are not subject to GHG reporting requirements.
In 2007, the state of Hawaii passed Act 234, which required that GHG emissions be rolled back on a statewide basis to 1990 levels by the year 2020. Although delayed, the Hawaii Department of Health (“DOH”) has issued regulations that would require each major facility to reduce CO2 emissions by 16% by 2020 relative to a calendar year 2010 baseline (the first year in which GHG emissions were reported to the EPA under 40 CFR Part 98). The final version of the state’s GHG rules included an alternative for facilities to demonstrate that further GHG reductions are not economically viable and an additional provision that authorized the DOH to issue a waiver if GHGs are being effectively controlled as a consequence of other state initiatives and regulations such as the Renewable Portfolio Standard. The Hawaii refinery’s capacity to further reduce fuel use and GHG emissions is limited. Since Hawaii’s GHG emissions have already been reduced below 2010 levels and are projected to be less than the 1990 levels by 2020, we anticipate the Hawaii refinery will be able to demonstrate that no further reductions are required to meet the statewide goal. Any reductions imposed by the 16% facility-specific mandate would not be cost-effective and therefore should not be required. Additionally, the regulation allows for “partnering” with other facilities (principally power plants) which have already dramatically reduced greenhouse emissions or are on schedule to reduce CO2 emissions in order to comply with the state’s Renewable Portfolio Standards.
Regulation of GHG emissions is new and highly controversial. Further regulatory, legislative and judicial developments are likely to occur in the future. Such developments may affect how these GHG initiatives will impact us. They may also impact the use of and demand for petroleum products, which could impact our business. Further, apart from these developments, tort claims alleging property damage against GHG emissions sources may be asserted. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us. 
National Ambient Air Quality Standards
Over the past several years the EPA has adopted a number of new and more stringent National Ambient Air Quality Standards ("NAAQS"). Specifically new NOX and SO2 standards were set in 2010 and a new particulate matter standard was set in 2012. States are required to develop State Implementation Plans and ultimately local air districts are required to adopt rules that will (over time) improve the air quality so that it will be “In Attainment” with the existing and new NAAQS. More stringent air

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pollutant standards and corresponding rules have already impacted and will continue to cause many refineries to invest heavily in additional air pollution controls. Thus far, Hawaii air quality, particularly on Oahu where our Hawaii refinery is located, has met even the most recent NAAQS and the Hawaii refinery itself has not been required to install new controls as result of local rules. Even so, NAAQS could and to a degree have already forced some changes for our customer base. Power plants on the Big Island, where SO2 levels are already elevated due to volcanic activity, are switching from LSFO to diesel fuel. On Oahu, the state’s largest utility frequently cites compliance with NAAQS as one of its justifications for moving towards a cleaner bridge fuel, potentially diesel or LNG before reaching its renewable goals. On October 1, 2015, the EPA adopted rules that would substantially tighten the NAAQS for ground-level ozone. This rule will cause many areas of the country to fall out of attainment and for the affected states to require additional controls and limits on combustion emissions and emissions of volatile organic compounds. We do not currently anticipate that the more stringent NAAQS will impact our Hawaii or Wyoming operations.
Regulation of Industrial Customer Base through Mercury Air Toxics Standard
Additional federal regulation of Hawaii-based power plants will likely have an impact on our Hawaii refinery because a portion of its production capacity and product mix has historically been dedicated to supplying industrial fuel oil for the islands’ public utilities. On February 16, 2012, the EPA published National Emission Standards for Hazardous Air Pollutants ("NESHAPS") for existing fossil-fuel-fired Electrical Utility Steam Generating Units ("EGU’s") (under 40 CFR 63 Subpart UUUUU). The regulation, known more commonly as the Mercury Air Toxics Standard ("MATS") was originally focused on limiting the amount of mercury and acid gas from the nation’s coal-fired power plants. However, the regulation extends to oil-fired power plants as well. While our Hawaii refinery can be tuned, operated and modified to respond to a shift in customer fuel specifications and additional demand for distillates, an ongoing surplus of residual fuels (produced by both Hawaii-based refineries) will likely put pressure on margins and necessitate alternative marketing and distribution strategies.
Fuel Standards
In 2007, the U.S. Congress passed the Energy Independence and Security Act (“EISA”) which, among other things, set a target fuel economy standard of 35 miles per gallon for the combined fleet of cars and light trucks in the U.S. by model year 2020 and contained a second Renewable Fuel Standard (the “RFS2”). In August 2012, the EPA and National Highway Traffic Safety Administration jointly adopted regulations that establish an average industry fuel economy of 54.5 miles per gallon by model year 2025. The RFS2 requires an increasing amount of renewable fuel usage, up to 36.0 billion gallons by 2022. In the near term, we, like many other refiners, plan to satisfy the RSF2 requirement primarily by blending denatured ethanol fuel into gasoline. Since the RFS2 is applicable to diesel fuel as well as gasoline and since we did not blend in any biodiesel in 2014, we satisfied our overall RFS obligation through the acquisition of renewable credits referred to as Renewable Identification Numbering System ("RINS"). The RFS2 may present production and logistics challenges for both the renewable fuels and petroleum refining and marketing industries in that we may have to enter into arrangements with other parties or purchase credits from the EPA to meet our obligations to use advanced biofuels, including biomass-based diesel and cellulosic biofuel, with potentially uncertain supplies of these new fuels and RINS.
In October 2010, the EPA issued a partial waiver decision under the CAA to allow for an increase in the amount of ethanol permitted to be blended into gasoline from 10% ("E10") to 15% ("E15") for 2007 and newer light duty motor vehicles. There are numerous issues, including state and federal regulatory issues, which need to be addressed before E15 can be marketed on a large scale for use in traditional gasoline engines. Consequently, unless the federal regulations are revised, qualified RINS will be required to fulfill the federal mandate for renewable fuels. We may experience a decrease in demand for refined petroleum products due to an increase in combined fleet mileage or due to refined petroleum products being replaced by renewable fuels.
In March 2014, the EPA published a final Tier 3 gasoline standard that lowers the allowable sulfur level in gasoline to 10 parts per million ("ppm") and also lowers the allowable benzene, aromatics and olefins content of gasoline. The effective date for the new standard, January 1, 2017, provided refiners nationwide little time to engineer, permit and implement substantial modifications; however, approved small volume refineries have until January 1, 2020 to meet the standard. PHR submitted its application to the EPA for small volume refinery status on December 30, 2014 and the EPA approved the application on September 9, 2015. However, PHR exceeded the 75 thousand barrel average aggregate daily crude oil throughput limit for small volume refineries in 2015 and was therefore disqualified from small volume refinery effective as of June 21, 2016. PHR is required to comply with Tier 3 gasoline standards within 30 months of this date. On March 19, 2015, the EPA confirmed the small refinery status of our Wyoming refinery.
Beginning on June 30, 2014, new sulfur standards for fuel oil used by marine vessels operating within 200 miles of the U.S. coastline (which includes the entire Hawaiian Island chain) was lowered from 10,000 ppm (1%) to 1,000 ppm (0.1%). The sulfur standards began at the Hawaii refinery and were phased in so that by January 1, 2015, they were to be fully aligned with the International Marine Organization ("IMO") standards and deadline. The more stringent standards apply universally to both U.S. and foreign flagged ships. Although the marine fuel regulations provided vessel operators with a few compliance options

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such as installation of on-board pollution controls and demonstration unavailability, many vessel operators will be forced to switch to a distillate fuel while operating within the Emission Control Area ("ECA"). Beyond the 200 mile ECA, large ocean vessels are still allowed to burn marine fuel with up to 3.5% sulfur. Our Hawaii refinery is capable of producing the 1% sulfur residual fuel oil that was previously required within the ECA. Although our Hawaii refinery remains in a position to supply vessels traveling to and through Hawaii, the market for 0.1% sulfur distillate fuel and 3.5% sulfur residual fuel is much more competitive.
There will be compliance costs and uncertainties regarding how we will comply with the various requirements contained in the EISA and other fuel-related regulations.
Solid and Hazardous Waste 
Several of our businesses generate wastes, including hazardous wastes, which are subject to regulation under the federal Resource Conservation and Recovery Act (“RCRA”) and state statutes. The EPA has limited the disposal options for certain hazardous wastes and state regulation of the handling and disposal of refining and natural gas and oil exploration and production wastes and solid wastes is becoming more stringent. Furthermore, it is possible that certain wastes generated by our natural gas and oil operations which are currently exempt from regulation as “hazardous wastes” may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes and therefore be subject to more rigorous and costly disposal requirements. 
Naturally Occurring Radioactive Materials (“NORM”) are radioactive materials that accumulate on production equipment or area soils during oil and natural gas extraction or processing. NORM wastes are regulated under the RCRA framework, although such wastes may qualify for the oil and gas hazardous waste exclusion. Primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM-contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards. 
Our natural gas and oil properties have been operated by third parties that controlled the treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to refineries and to natural gas and oil wastes and properties have gradually become stricter over time. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators) or to perform remedial operations to prevent future contamination. 
Superfund 
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release or threatened release of a “hazardous substance” into the environment. These persons include the current owner and operator of a site, any former owner or operator who operated the site at the time of a release, transporters and persons that disposed or arranged for the disposal of hazardous substances at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible persons the costs of such action. State statutes impose similar liability.
Under CERCLA, the term “hazardous substance” does not include “petroleum, including crude oil or any fraction thereof,” unless specifically listed or designated and the term does not include natural gas, NGLs, liquefied natural gas or synthetic gas usable for fuel. While this “petroleum exclusion” lessens the significance of CERCLA to our exploration and production operations, we may generate wastes that may fall within CERCLA’s definition of a “hazardous substance” in the course of our ordinary refining and natural gas and oil operations. Although we and, to our knowledge, our predecessors have used operating and disposal practices that were standard in the industry at the time, “hazardous substances” may have been disposed or released on, under, or from the properties currently or historically owned or leased by us or on, under, or from other locations where these wastes have been taken for disposal. At this time, we do not believe that we have any liability associated with any Superfund site and we have not been notified of any claim, liability or damages under CERCLA. 
Oil Pollution Act 
The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from such spills in U.S. waters. A “responsible party” includes the owner or operator of a facility or vessel or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for crude oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party

13




fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. 
The OPA establishes a liability limit for onshore facilities of $633.85 million and for offshore facilities of all removal costs plus $133.65 million and lesser limits for some vessels depending upon their size. The regulations promulgated under OPA impose proof of financial responsibility requirements that can be satisfied through insurance, guarantee, indemnity, surety bond, letter of credit, qualification as a self-insurer or a combination thereof. The amount of financial responsibility required depends upon a variety of factors including the type of facility or vessel, its size, storage capacity, throughput, proximity to sensitive areas, type of oil handled, history of discharges and other factors. Failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. The federal Bureau of Ocean Energy Management (“BOEM”) has proposed to increase the OPA liability limit for offshore facilities. Further, the U.S. Congress has considered legislation that could increase our obligations and potential liability under the OPA, including by eliminating the current cap on liability for damages and increasing minimum levels of financial responsibility. It is uncertain whether, and in what form, such legislation may ultimately be adopted. We are not aware of the occurrence of any action or event that would subject us to liability under OPA and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us. 
Discharges 
The Clean Water Act (“CWA”) regulates the discharge of pollutants to waters of the U.S., including wetlands, and requires a permit for the discharge of pollutants, including petroleum, to such waters. Certain facilities that store or otherwise handle oil are required to prepare and implement Spill Prevention, Control and Countermeasure Plans and Facility Response Plans relating to the possible discharge of oil to surface waters. We are required to prepare and comply with such plans and to obtain and comply with discharge permits. We believe we are in substantial compliance with these requirements and that any noncompliance would not have a material adverse effect on us. The CWA also prohibits spills of oil and hazardous substances to waters of the U.S. in excess of levels set by regulations and imposes liability in the event of a spill. 
State laws further regulate discharges of pollutants to surface and groundwaters, require permits that set limits on discharges to such waters and provide civil and criminal penalties and liabilities for spills to both surface and groundwaters. Some states have imposed regulatory requirements to respond to concerns related to potential for groundwater impact from oil and gas exploration and production. For example, the Colorado Oil and Gas Conservation Commission (“COGCC”) approved rules that require sampling of groundwater for hydrocarbons and other indicator compounds both before and after drilling. Sampling results are to be reported to the COGCC, which maintains a water quality database online and available to the public. 
Hydraulic Fracturing 
Our and Laramie Energy's exploration and production activities may involve the use of hydraulic fracturing techniques to stimulate wells and maximize natural gas production. Citing concerns over the potential for hydraulic fracturing to impact drinking water, human health and the environment and in response to a congressional directive, the EPA has commissioned a study to identify potential risks associated with hydraulic fracturing. In June 2015, the EPA released for public comment and peer review, a draft assessment of the potential impacts of hydraulic fracturing on drinking water resources. Additionally, the draft generated substantial public comment and the EPA’s Science Advisory Board scheduled public meetings and teleconferences through at least March 2016 to receive comment on the study. The study was intended to improve scientific understanding to guide the EPA’s regulatory oversight, guidance and, where appropriate, rulemaking related to hydraulic fracturing. The EPA study was released in December 2016 and it concluded that hydraulic fracturing activities can impact drinking water under certain circumstances, a conclusion that may lead to additional regulation. Some states and localities now regulate the utilization of hydraulic fracturing and other states and localities are in the process of developing, or are considering development of, such rules. In some states, courts are in the process of determining whether local bans or other regulation of oil and gas exploration and production activity are preempted by statewide regulatory programs. A state ballot initiative was introduced in Colorado to amend the state constitution to give local governments control over oil and natural gas drilling in their areas, but the ballot initiative failed. Additionally, the Colorado Supreme Court ruled in May 2016 that local governments in that state lacked authority to ban hydraulic fracturing. Given the results of the EPA study and other developments related to hydraulic fracturing, however, our and Laramie Energy's drilling activities could be subjected to new or enhanced federal, state and/or local regulatory requirements governing hydraulic fracturing, including requirements that would restrict the areas in which we are able to operate. 
Air Emissions 
Our refining operations and our and Laramie Energy's exploration and production operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits may be resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could impose civil and criminal liability for non-compliance. An agency could

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require us to forego construction or operation of certain air emission sources. We believe that we are in substantial compliance with air pollution control requirements and that, if a particular permit application were denied, we would have enough permitted or permittable capacity to continue our operations without a material adverse effect on any particular producing field. 
Our refining business is subject to very significant state and federal air permitting and pollution control requirements, including some that are the subject of ongoing enforcement activities by the EPA as described in more detail below. The EPA continues to review and, in many cases, tighten ambient air quality standards, which standards, along with the advancement of pollution control technologies, result in new regulatory and permit requirements that will impact our refining activities and involve additional costs.
On September 29, 2015, the EPA announced a final rule updating standards that control toxic air emissions from petroleum refineries, addressing, among other things, flaring operations, fenceline air quality monitoring and additional emission reductions from storage tanks and delayed coking units. Affected existing sources will be required to comply with the new requirements no later than 2018, with certain refiners required to comply earlier depending on the relevant provision and refinery construction date. We do not anticipate that compliance with this rule will have a material impact on our financial condition, results of operations or cash flows.
With respect to our and Laramie Energy's exploration and production activities, the EPA has finalized new rules to limit air emissions from many hydraulically fractured natural gas wells. These regulations require use of equipment to capture gases that come from such wells during the drilling process (so-called green completions). Other new requirements, many effective in 2013, involved tighter standards for emissions associated with natural gas production, storage and transport. In June 2016, the EPA published final rules to address methane emissions of new oil and gas wells and in November 2016, the BLM published new rules to limit flaring on public and tribal lands. While these new requirements increased the cost of natural gas production, neither we nor Laramie Energy were affected any differently than other producers of natural gas.
More stringent regulation may be imposed in the future as a result of public concern about the impacts of increased oil and gas drilling activity and the availability of new information. For example, the Colorado Department of Natural Resources and the Colorado Department of Public Health and the Environment have announced plans for a study of emissions tied to oil and gas development in areas along the northern Front Range of the Rocky Mountains. Due to uncertainties regarding the outcome of such studies and potential new regulatory proposals, we are unable to predict the financial impact of such developments on our company going forward. 
Coastal Coordination 
There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed to preserve and, where possible, restore the natural resources of the coastal zone of the U.S. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development. 
Environmental Agreement 
On September 25, 2013 (the “Closing Date”), Par Petroleum, LLC (formerly known as Hawaii Pacific Energy; a wholly owned subsidiary of Par created for purposes of acquiring PHR), Tesoro and PHR entered into an Environmental Agreement (“Environmental Agreement”), which allocated responsibility for known and contingent environmental liabilities related to the acquisition of PHR as follows: 
Consent Decree
On July 18, 2016, PHR and subsidiaries of Tesoro entered into a consent decree with the EPA, the U.S. Department of Justice ("DOJ") and other state governmental authorities concerning alleged violations of the federal CAA related to the ownership and operation of multiple facilities owned or formerly owned by Tesoro and its affiliates ("Consent Decree"), including our Hawaii refinery. As a result of the Consent Decree, PHR expanded its previously-announced 2016 Hawaii refinery turnaround to undertake additional capital improvements to reduce emissions of air pollutants and to provide for certain NOx and SO2 emission controls and monitoring required by the Consent Decree. Although the turnaround was completed during the third quarter of 2016, work related to the Consent Decree is ongoing and the parties continue to work together to address the EPA's requirements. This work subjects us to risks associated with engineering, procurement and construction of improvements and repairs to our facilities and related penalties and fines to the extent applicable deadlines under the Consent Decree are not satisfied, as well as risks related to the performance of equipment required by, or affected by, the Consent Decree. Each of these risks could have a material adverse effect on our business, financial condition, or results of operations.

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We estimate the cost of compliance with the Consent Decree to be approximately $30.0 million. However, Tesoro is responsible under the Environmental Agreement to reimburse PHR for all reasonable third-party capital expenditures incurred pursuant to the Consent Decree to the extent related to acts or omissions prior to the Closing Date. Tesoro is obligated to pay all applicable fines and penalties related to the Consent Decree. As of December 31, 2016, Tesoro has reimbursed us for $6.3 million of the total capital expenditures of $9.6 million incurred in 2016 in connection with the Consent Decree. Net capital expenditures and reimbursements related to the Consent Decree are presented within Capital expenditures on our consolidated statement of cash flows for the year ended December 31, 2016. Please read Note 14—Commitments and Contingencies to our consolidated financial statements under Item 8 of this Form 10-K for more information.
Indemnification
In addition to its obligation to reimburse us for capital expenditures incurred pursuant to the Consent Decree, Tesoro agreed to indemnify us for claims and losses arising out of related breaches of Tesoro’s representations, warranties and covenants in the Environment Agreement, certain defined “corrective actions” relating to pre-existing environmental conditions, third-party claims arising under environmental laws for personal injury or property damage arising out of, or relating to, releases of hazardous materials that occurred prior to the Closing Date, any fine, penalty or other cost assessed by a governmental authority in connection with violations of environmental laws by us prior to the Closing Date, certain groundwater remediation work, the replacement of underground storage tanks located at certain retail assets, fines or penalties imposed on us by the Consent Decree related to acts or omissions of Tesoro prior to the Closing Date and related to the Pearl City Superfund Site. 
Tesoro’s indemnification obligations are subject to certain limitations as set forth in the Environmental Agreement. These limitations include a deductible of $1 million and a cap of $15 million for certain of Tesoro’s indemnification obligations related to certain pre-existing conditions as well as certain restrictions regarding the time limits for submitting notice and supporting documentation for remediation actions.
Other Government Regulation 
Sales and Transportation of Natural Gas 
Historically, the transportation and sales for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and Federal Energy Regulatory Commission (“FERC”) regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated the price for all “first sales” of natural gas. Thus, all of our sales of gas may be made at market prices, subject to applicable contract provisions. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. Since 1985, the FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. We cannot predict what further action the FERC will take on these matters. Some of the FERC’s more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which we compete. 
The Outer Continental Shelf Lands Act (“OCSLA”), which was administered by the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) and, after October 1, 2011, its successors, the BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”) and the FERC, requires that all pipelines operating on or across the shelf provide open-access, non-discriminatory service. There are currently no regulations implemented by the FERC under its OCSLA authority on gatherers and other entities outside the reach of its NGA jurisdiction. Therefore, we do not believe that any FERC, BOEM or BSEE action taken under OCSLA will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers with which we compete. 
Natural gas continues to supply a significant portion of North America’s energy needs and we believe the importance of natural gas in meeting this energy need will continue, although natural gas supply and demand fundamentals have resulted in extremely volatile natural gas prices, which is expected to continue. 
On August 8, 2005, the Energy Policy Act of 2005 (“2005 EPA”) was signed into law. This comprehensive act contains many provisions that will encourage natural gas and oil exploration and development in the U.S. The 2005 EPA directs the FERC, BOEM and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends the NGA to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material

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fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas.
In 2007, the FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMbtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report, on May 1 of each year beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to, the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. The monitoring and reporting required by these rules have increased our administrative costs. We do not anticipate that we will be affected any differently than other producers of natural gas. 
Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are subject to applicable contract provisions made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to the FERC’s jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. 
The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC’s regulation of gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation by the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, pipeline rates are subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market-based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. 
Federal Leases 
We maintain operations located on federal oil and natural gas leases, which are administered by the BOEMRE, BOEM or BSEE, pursuant to the OCSLA. The BOEMRE and its successors, the BOEM and the BSEE, regulate offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on offshore California and removal of facilities. 
On January 19, 2011, the U.S. Department of the Interior announced that it would divide offshore oil and gas responsibilities among three separate agencies, with the reorganization to be completed in 2011. The Department of the Interior first created the Office of Natural Resources Revenue to manage revenue collection on October 1, 2010. Effective October 1, 2011, the remaining functions of BOEMRE were split into two federal bureaus, the BOEM, which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, NEPA analysis and environmental studies and the BSEE, which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, after October 1, 2011, we are required to interact with two federal bureaus to obtain approval of our exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays. Our federal oil and natural gas leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require compliance with detailed BOEMRE regulations and orders that are subject to interpretation and change by the BOEM or BSEE. The BOEMRE has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines and the BOEM or the BSEE may in the future amend these regulations.
To cover the various obligations of lessees on the Outer Continental Shelf (“OCS”), the BOEMRE and its successors generally require that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be

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satisfied. The cost of these bonds or assurances can be substantial and there is no assurance that they can be obtained in all cases. We are currently exempt from supplemental bonding requirements. As many regulations are being reviewed, we may be subject to supplemental bonding requirements in the future. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and results of operations. 
The Office of Natural Resources Revenue (“ONRR”) in the U.S. Department of the Interior administers the collection of royalties under the terms of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is based upon the terms of the oil and natural gas leases as well as the regulations promulgated by the ONRR. 
Federal, State or American Indian Leases 
In the event we conduct operations on federal, state or American Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”), BOEM or other appropriate federal or state agencies. 
The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the U.S. Such restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation’s lease can be cancelled in a proceeding instituted by the U.S. Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in numerous federal onshore oil and gas leases. It is possible that holders of our equity interests may be citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act. 
State Regulations 
Most states regulate the production and sale of oil and natural gas, including: 
requirements for obtaining drilling permits;
the method of developing new fields;
the spacing and operation of wells;
the prevention of waste of oil and natural gas resources; and
the plugging and abandonment of wells.
The rate of production may be regulated and the maximum daily production allowable from both oil and natural gas wells may be established on a market demand or conservation basis or both. 
We may enter into agreements relating to the construction or operation of a pipeline system for the transportation of natural gas. To the extent that such natural gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the jurisdiction of such state’s administrative authority charged with the responsibility of regulating intrastate pipelines. In such an event, the rates that we could charge for gas, the transportation of natural gas and oil and the construction and operation of such pipeline would be subject to the rules and regulations governing such matters, if any, of such administrative authority. 
For example, in August 2013, the COGCC implemented new setback rules for oil and natural gas wells and production facilities near occupied buildings. The COGCC increased its setback distance to a uniform 500 feet statewide setback from occupied buildings and a uniform 1,000 feet statewide setback from high occupancy building units. The new setback rules also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface owners and the owners of occupied building units. The new rules also require operators to provide advance notice to surface owners within 500 feet of proposed operations, the owners of occupied buildings within 1,000 feet of proposed operations and local governments prior to the filing of an Application for Permit to Drill or Oil and Gas Location Assessment. The new rules include expanded outreach and communication efforts by an operator.
In January 2013, the COGCC also approved two rules that require operators to sample groundwater for hydrocarbons and other indicator compounds both before and after drilling. The new statewide rule requires sampling of up to four water wells within a half mile radius of a new natural gas and oil well before drilling, two samples between six and 12 months after completion and two more samples between five and six years after completion. The revised rule for the Greater Wattenberg Area (“GWA”) requires operators to sample one water well per quarter governmental section before drilling and between six to 12 months after completion. 

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Legislative Proposals 
In the past, Congress has been very active in the area of natural gas regulation. New legislative proposals in Congress and the various state legislatures, if enacted, could significantly affect the natural gas and oil industry. At the present time it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on our operations. 
Impact of Dodd-Frank Act Derivatives Regulation 
The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which was passed by Congress and signed into law in July 2010, contains significant derivatives regulation, including requirements that certain transactions be cleared on exchanges and that collateral (commonly referred to as “margin”) be posted for such transactions. The Dodd-Frank Act provides for a potential exception from these clearing and collateral requirements for commercial end-users and it includes a number of defined terms used in determining how this exception applies to particular derivative transactions and the parties to those transactions. As required by the Dodd-Frank Act, the Commodities Futures and Trading Commission (“CFTC”) has promulgated numerous rules to define these terms. The CFTC’s final rules establishing position limits for certain derivatives transactions were vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on certain core futures and equivalent swap contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new positions limit rules are not yet final, the impact of those provisions on us is uncertain at this time. 
It is possible that the CFTC, in conjunction with prudential regulators, may mandate that financial counterparties entering into swap transactions with end-users must do so with credit support agreements in place, which could result in negotiated credit thresholds above which an end-user must post collateral. If this should occur, we intend to manage our credit relationships to minimize collateral requirements. 
The CFTC’s final rules may also have an impact on our hedging counterparties. For example, our bank counterparties may be required to post collateral and assume compliance burdens resulting in additional costs. We expect that much of the increased costs could be passed on to us, thereby decreasing the relative effectiveness of our hedges and our profitability. To the extent we incur increased costs or are required to post collateral, there could be a corresponding decrease in amounts available for our capital investment program. 
OSHA 
We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize and/or disclose information about hazardous materials used or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens.
SIGNIFICANT CUSTOMERS
We sell a variety of refined products to a diverse customer base. The majority of our refined products are primarily sold through short-term contracts or on the spot market. For the year ended December 31, 2016, no single customer accounted for 10% or more of our revenues.
EMPLOYEES
At December 31, 2016, we employed 863 people, 141 of whom are nonexempt employees at the Hawaii refinery who are represented by the United Steelworkers Union ("USW"). Our previous collective bargaining agreement with the union expired in January 2015.  On March 23, 2015, the union ratified a four-year extension of the collective bargaining agreement. On January 13, 2016, a claim against us was brought to the United States National Labor Relations Board ("NLRB") alleging a refusal to bargain collectively and in good faith. Notwithstanding the pending claim before the NLRB, we consider our relations with our represented and non-represented employees to be satisfactory.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Annual Report on Form 10-K may constitute “forward-looking” statements as defined in Section 27A of the Securities Act of 1933 (the "Securities Act"), Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”), the Private Securities Litigation Reform Act of 1995 (“PSLRA”) or in releases made by the SEC, all as may be amended

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from time to time. Such forward-looking statements involve known and unknown risks, uncertainties and other important factors that could cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by such forward-looking statements. Statements that are not historical fact are forward-looking statements. Forward-looking statements can be identified by, among other things, the use of forward-looking language, such as the words “plan,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “may,” “will,” “would,” “could,” “should,” “seeks,” or “scheduled to,” or other similar words or the negative of these terms or other variations of these terms or comparable language or by discussion of strategy or intentions. These cautionary statements are being made pursuant to the Securities Act, the Exchange Act and the PSLRA with the intention of obtaining the benefits of the “safe harbor” provisions of such laws. 
The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance and we cannot assure any reader that such statements will be realized or that the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Item 1A. — Risk Factors”, “Item 7. — Management's Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this Annual Report on Form 10-K. All forward-looking statements speak only as of the date they are made. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Item 1A. RISK FACTORS
Our businesses involve a high degree of risk. You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this Annual Report on Form 10-K. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, prospects, financial condition, results of operations or cash flows could be materially adversely affected. In any such case, the trading price of our common stock could decline. The risks described below are not the only ones facing our company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us.
OPERATING RISKS
Our operations are subject to operational hazards that could expose us to potentially significant losses.
Our operations are subject to potential operational hazards and risks inherent in refining operations, in transporting and storing crude oil and refined products and in producing natural gas and oil. Any of these risks, such as fires, explosions, maritime disasters, security breaches, pipeline ruptures and spills, mechanical failure of equipment and severe weather and natural disasters at our or third-party facilities could result in business interruptions or shutdowns and damage to our properties and the properties of others. A serious accident at our facilities could also result in serious injury or death to our employees or contractors and could expose us to significant liability for personal injury claims and reputational risk. Any such event or unplanned shutdown could have a material adverse effect on our business, financial condition and results of operations.
The volatility of crude oil prices and refined product prices and changes in the demand for such products may have a material adverse effect on our cash flow and results of operations.
Earnings and cash flows from our refining segment depend on a number of factors, including to a large extent the cost of crude oil and other refinery feedstocks which has fluctuated significantly in recent years. While prices for refined products are influenced by the price of crude oil, the constantly changing margin between the price we pay for crude oil and other refinery feedstocks and the prices we receive for refined products (“crack spread”) also fluctuates significantly. The prices we pay and prices we receive depend on numerous factors beyond our control, including the global supply and demand for crude oil, gasoline and other refined products, which are subject to, among other things:
changes in the global economy and the level of foreign and domestic production of crude oil and refined products;
availability of crude oil and refined products and the infrastructure to transport crude oil and refined products;
local factors, including market conditions, the level of operations of other refineries in our markets and the volume and price of refined products imported;
threatened or actual terrorist incidents, acts of war and other global political conditions;
government regulations; and
weather conditions, hurricanes or other natural disasters.
In addition, we purchase our refinery feedstocks 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 impact on our financial results. We purchase refined products manufactured by others for sale to our customers. Price level changes during the periods between purchasing and selling these refined products could also have a material adverse effect on our business, financial condition and results of operations.
Our investment in Laramie Energy is impacted by changing commodity prices. Laramie Energy primarily sells natural gas and natural gas liquids, and adverse changes in those commodity prices would impact the value of our investment in Laramie Energy.
Instability in the global economic and political environment can lead to volatility in the cost and availability of crude oil and prices for refined products, which could adversely impact our results of operations.
Instability in the global economic and political environment can lead to volatility in the cost and availability of crude oil and in the price for refined products. This may place downward pressure on our results of operations. This is particularly true of developments in and relating to oil-producing countries, including terrorist activities, military conflicts, embargoes, internal instability or actions or reactions of the U.S. or foreign governments in anticipation of, or in response to, such developments.  Any such events may limit or disrupt markets, which could negatively impact our ability to access global crude oil commodity flows or sell our refined products.


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Many of our refined products could cause serious injury or death if mishandled or misused by us or our purchasers, or if defects occur during manufacturing.
While we produce, store, transport and deliver all of our refined products in a safe manner, many of our refined products are highly flammable or explosive and could cause significant damage to persons or property if mishandled. Defects in our products (such as gasoline or jet fuel) or misuse by us or by end purchasers could lead to fatalities or serious damage to property. We may be held liable for such occurrences which could have a material adverse effect on our business and results of operations.
Our business is impacted by increased risks of spills, discharges or other releases of petroleum or hazardous substances in our refining and logistics operations and in third-party natural gas and oil production operations in which we have a working interest.
The operation of refineries, pipelines and refined products terminals and the production of natural gas and oil is subject to increased risks of spills, discharges or other inadvertent releases of petroleum or hazardous substances. These events could occur in connection with the operation of our refineries, pipelines or refined products terminals, or third-party drilling and production activities in which we have a working interest or at third-party facilities that receive our wastes or by-products for treatment or disposal. If any of these events occur, or is found to have previously occurred, we could be liable for costs and penalties associated with their remediation under federal, state and local environmental laws or common law, and could be liable for property damage to third parties caused by contamination from releases and spills. The penalties and clean-up costs that we may have to pay for releases or the amounts that we may have to pay to third parties for damages to their property, could be significant and have a material adverse effect on our business, results of operations or financial condition.
We operate in and adjacent to environmentally sensitive coastal waters where tanker, pipeline and refined product transportation and storage operations are closely regulated by federal, state and local agencies and monitored by environmental interest groups. Operations by third-party drilling and production entities in which we have a working interest that are adjacent to navigable waters such as rivers and lakes are similarly subject to stringent regulations. Transportation and storage of crude oil and refined products over and adjacent to regulated waters involves increased risk subjecting us to the provisions of the OPA, and state laws in Hawaii and Colorado. Among other things, these laws require us and the owners of tankers that we charter to deliver crude oil to our Hawaii refinery to demonstrate in some situations the capacity to respond to a spill of up to one million barrels of oil from a tanker and up to 600 thousand barrels of oil from an above-ground storage tank adjacent to water, which we refer to as a “Worst Case Discharge,” to the maximum extent possible.
We and third-party drilling and production entities in which we have a working interest and the owners of tankers we charter have contracted with various spill response service companies in the areas in which we transport and store crude oil and refined products to meet the requirements of the OPA and applicable state and foreign laws. However, there may be accidents involving tankers, pipelines, railcars or above ground storage tanks transporting or storing crude oil or refined products, and response services may not respond to a Worst Case Discharge in a manner that will adequately contain that discharge, or we may be subject to liability in connection with any unauthorized discharge. Additionally, we cannot ensure that all resources of a contracted response service company could be available for our or a chartered tanker owner’s use at any given time. There are many factors that could inhibit the availability of these resources, including, but not limited to, weather conditions, governmental regulations or moratoria or other global events. State or federal rulings could require that these resources could be diverted to respond to other events.
Our operations, including the operation of underground storage tanks, are also subject to the risk of environmental litigation and investigations which could affect our results of operations.
From time to time we have been, and presently are, subject to litigation and investigations with respect to environmental and related matters. We may become involved in further litigation or other proceedings, or we may be held responsible in any existing or future litigation or proceedings, the costs of which could be material.
We operate, and have in the past operated, fueling stations with underground storage tanks in Hawaii used primarily for storing and dispensing refined fuels. In addition, some of our fueling stations have been owned by third parties whose operation of the stations was not under our control.
Federal and state regulations and legislation govern the storage tanks and compliance with these requirements can be costly. The operation of underground storage tanks poses certain risks, including leaks. Leaks from underground storage tanks, which may occur at one or more of our fueling stations, may impact soil or groundwater and could result in fines or civil liability for us.

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Our insurance coverage may be inadequate to protect us from the liabilities that could arise in our business.
We carry property, casualty, business interruption and other lines of insurance but we do not maintain insurance coverage against all potential losses. Marine vessel charter agreements do not include indemnity provisions for oil spills so we also carry marine charterer’s liability insurance. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Claims covered by insurance are subject to deductibles, the aggregate amount of which could be material. Insurance policies are also subject to compliance with certain conditions, the failure of which could lead to a denial of coverage as to a particular claim or the voiding of a particular insurance policy. There also can be no assurance that existing insurance coverage can be renewed at commercially reasonable rates or that available coverage will be adequate to cover future claims. The occurrence of an event that is not fully covered by insurance or failure by one or more insurers to honor its coverage commitments for an insured event could have a material adverse effect on our business, financial condition and results of operations.
We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil and refined products to and from our Hawaii refinery.
Our Hawaii refinery receives its crude oil via tankers and transports refined products from Oahu to Hawaii, Maui, Molokai and Kauai via barge. In addition to environmental risks, we could experience an interruption of supply or an increased cost to deliver refined products to market if the ability of the pipelines or vessels to transport crude oil or refined products is disrupted because of accidents, governmental regulation or third-party action. A prolonged disruption of the ability of a pipeline or vessels to transport crude oil or refined products could have a material adverse effect on our business, financial condition and results of operations.
The financial and operating results for our refineries in Hawaii and Wyoming, including the products they refine and distribute, can each be seasonal.
The operating results of each of our refineries, including the products they refine and sell, can be seasonal. Demand for gasoline in Wyoming and South Dakota is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. Wyoming Refining's financial and operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year as a result of this seasonality. Conversely, the demand for the products the Hawaii refinery refines and sells, and the financial and operating results for the Hawaii refinery, are often strongest in first and fourth calendar quarters.
We rely upon certain critical information systems for the operation of our business and the failure of any critical information system, including a cyber security breach, may result in harm to our business.
We are heavily dependent on our technology infrastructure and maintain and rely upon certain critical information systems for the effective operation of our business. These information systems include data network and telecommunications, internet access and our websites and various computer hardware equipment and software applications, including those that are critical to the safe operation of our refineries and our pipelines and terminals. Our retail business collects certain customer data, including credit card numbers, for business purposes. The integrity and protection of our customer, employee and company data is critical to our business.
Our information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber attacks and other events. To the extent that these information systems are under our control, we have implemented measures such as virus protection software and intrusion detection systems, to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe. Any compromise of our data security or our inability to use or access these information systems at critical points in time could unfavorably impact the timely and efficient operation of our business and subject us to additional costs and liabilities, which could adversely affect our business, results of operations and financial condition. Finally, federal legislation relating to cyber security threats could impose additional requirements on our operations.
Through Laramie Energy, we are subject to all the risks of natural gas and oil exploration and production.
Through our investment in Laramie Energy and, to a lesser extent, through our other non-operated properties, we are exposed to all the risks inherent in natural gas and oil exploration and production, including the risks that:
we may not be able to replace production with new reserves;
exploration and development drilling may not result in commercially productive reserves;
title to properties in which we or Laramie Energy have interest may be impaired by title defects;
the marketability of our natural gas products depends mostly on the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities, which are owned by third parties;

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we have no long-term contracts to sell natural gas or oil;
compliance with environmental and other governmental requirements could result in increased costs of operation or curtailment, delay or cancellation of development and producing operations;
federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays;
changes in the demand for natural gas and oil could adversely affect our financial condition and results of operations;
natural gas drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water when it flows back to the wellbore. If we are unable to obtain adequate water supplies and dispose of the water we use or remove at a reasonable cost and within applicable environmental rules, our ability to produce natural gas commercially and in commercial quantities would be impaired.
We cannot control activities on properties we do not operate and we are unable to ensure the proper operation and profitability of these non-operated properties.
We are a non-operator with respect to our natural gas and oil properties. Consequently, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of leasehold acquisition, drilling and development activities therefore will depend upon a number of factors outside of our control, including:
timing and amount of capital expenditures;
expertise and diligence in adequately performing operations and complying with applicable agreements;
financial resources;
inclusion of other participants in drilling wells; and
use of technology.
As a result of any of the above, or any other failure of the operator to act in ways that are in our best interest, our results of operations and financial results could be adversely affected.
Our ability to extract value from our investment in Laramie Energy is limited.
Our 42.3% ownership interest in Laramie Energy is a significant asset. However, the ability of Laramie Energy to make distributions to its owners, including us, is currently prohibited by the terms of the Laramie Energy Credit Facility.
Information concerning our natural gas and oil reserves is uncertain.
There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The accuracy of an estimate of quantities of natural gas and crude oil reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future natural gas and crude oil prices, availability and terms of financing, expenditures for future development and exploitation activities and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities, natural gas and crude oil prices and regulatory changes. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from our assumptions and estimates. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same data. Further, the difficult financing environment may inhibit our ability to finance development of our reserves in the future.
The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves as of December 31, 2016, included herein were prepared by independent reserve engineers in accordance with the rules of the SEC and are not intended to represent the fair market value of such reserves. As required by the SEC, the estimated discounted present value of future net cash flows from proved reserves is generally based on prices and costs on the date of the estimate, while actual future prices and costs may be materially higher or lower. In addition, the 10% discount factor the SEC requires to be used to calculate discounted future net revenues for reporting purposes is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the natural gas and oil industry in general.
REGULATORY RISK
Meeting the requirements of evolving environmental, health and safety laws and regulations including those related to climate change could adversely affect our performance.
Consistent with the experience of other U.S. refineries, environmental laws and regulations have raised operating costs and may require significant capital investments at our refineries. We may be required to address conditions that may be discovered in the future and require a response. Potentially material expenditures could be required in the future as a result of evolving

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environmental, health and safety and energy laws, regulations or requirements that may be adopted or imposed in the future, as well as work that is ongoing related to the Consent Decree. Future developments in federal and state laws and regulations governing environmental, health and safety and energy matters are especially difficult to predict.
Currently, multiple legislative and regulatory measures to address GHG emissions (including CO2, methane and nitrous oxides) are in various phases of consideration, promulgation or implementation. These include actions to develop national, statewide or regional programs, each of which could require reductions in our GHG emissions. Requiring reductions in our GHG emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and/or (iii) administer and manage any GHG emissions programs, including acquiring emission credits or allotments.
Requiring reductions in our GHG emissions and increased use of renewable fuels which can be supplied by producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and individual customers could also decrease the demand for our refined products and could have a material adverse impact on our business, financial condition and results of operations.
Renewable fuels mandates may reduce demand for the petroleum fuels we produce, which could have a material adverse effect on our business results of operations and financial condition.

The EPA has issued Renewable Fuel Standard (“RFS”) mandates, requiring refiners such as us to blend renewable fuels into the petroleum fuels they produce and sell in the U.S. We, and other refiners subject to RFS, may meet the RFS requirements by blending the necessary volumes of renewable fuels produced by us or purchased from third parties. To the extent that refiners will not or cannot blend renewable fuels into the products they produce in the quantities required to satisfy their obligations under the RFS program, those refiners must purchase renewable credits, referred to as RINs, to maintain compliance. To the extent that we exceed the minimum volumetric requirements for blending of renewable fuels, we generate our own RINs for which we have the option of retaining the RINs for current or future RFS compliance or selling those RINs on the open market.

Under the RFS program, the volume of renewable fuels that obligated parties are required to blend into their finished petroleum fuels increases annually over time until 2022. Our refineries are subject to compliance with the RFS mandates. On November 30, 2015, the EPA issued final volume mandates for years 2014 through 2016, which are generally lower than the corresponding statutory mandates for those years.

Existing laws, regulations or regulatory initiatives could change and, notwithstanding that the EPA’s proposed volume mandates for 2014 through 2016 are generally lower than the corresponding statutory mandate for those years, the final minimum volumes of renewable fuels that must be blended with refined petroleum fuels could increase in the future. Despite a decline in RINs prices from relatively higher levels observed during mid-2013, we cannot currently predict the future prices of RINs and, thus, the expenses related to acquiring RINs in the future could increase relative to the cost in prior years. During 2016, we incurred $8.2 million and $4.0 million for RINs for our Hawaii and Wyoming refineries, respectively. We expect to incur approximately $8.5 million in 2017 for each of our refineries. Any increase in the final minimum volumes of renewable fuels that must be blended with refined petroleum fuels and/or any increase in the cost to acquire RINs has the potential to result in significant costs in connection with RINs compliance for 2017 and future years, which could be material and may have a material adverse impact on our business, financial condition and results of operations. Finally, while there is no current regulatory standard that authenticates RINs that may be purchased on the open market from third parties, we believe that the RINs we purchase are from reputable sources, are valid and serve to demonstrate compliance with applicable RFS requirements. However, if this belief proves incorrect and the RINs that we purchase are not valid or in compliance with applicable RFS requirements, our financial condition and cash flows may be adversely affected.
Potential legislative and regulatory actions addressing climate change could increase our costs, reduce our revenue and cash flow from natural gas and oil sales or otherwise alter the way we conduct our business.
The EPA has issued a notice of finding and determination that emissions of CO2, methane and other GHG present an endangerment to human health and the environment. In response, the EPA has adopted regulations under existing provisions of the federal CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit program requiring reviews for GHG emissions from certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. Moreover, on December 23, 2010, the EPA entered a settlement agreement with environmental groups requiring the agency to propose by December 10, 2011 GHG New Source Performance Standards (“NSPS”) for refineries and to finalize these rules by November 15, 2012. To date, the EPA has not completed those rulemakings and we do not know when they will be completed. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the U.S., including petroleum refineries and certain onshore petroleum and natural gas production activities, on an annual basis. We monitor for GHG emissions

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at our refineries, and believe we are in substantial compliance with the applicable GHG reporting requirements. Certain of the third-party drilling and production entities in which we hold a working interest also may be subject to reporting of GHG emissions in the U.S. These EPA policies and rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.
In addition, from time to time, the U.S. Congress has considered, and may in the future consider and adopt “cap and trade” legislation that would establish an economy-wide cap on GHG emissions in the U.S. and would require most sources of GHG emissions to obtain emission “allowances” corresponding to their annual GHG emissions. For those GHG sources that are unable to meet the required limitations, such legislation could impose substantial financial burdens. Any laws or regulations that may be adopted to restrict or reduce GHG emissions would likely require us to incur increased operating costs and could have an adverse effect on demand for our production. The adoption of any legislation or regulations that limits emissions of GHG from our or such drilling and production entities’ facilities, equipment and operations could require us or such entities to incur costs to reduce emissions of GHG associated with our or such entities operations or could adversely affect demand for the refined petroleum products that we produce or the crude oil or natural gas that such drilling and production entities in which we hold a working interest produce. Such regulations, if adopted, could increase costs of oil and natural gas operators, including Laramie Energy, in whom we have a non-operating working interest. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations as well as on third-party drilling and production activities in which we have a non-operating working interest.
In connection with the WRC Acquisition, we will be required to undertake significant remediation and other corrective actions with respect to certain environmental matters.
In connection with the WRC Acquisition, there are several environmental issues that will require us to undertake significant remediation efforts and other corrective actions. The Wyoming refinery is subject to a number of consent decrees, orders and settlement agreements involving the EPA and/or the Wyoming Department of Environmental Quality, some of which date back to the late 1970s and several of which remain in effect, requiring further actions at the Wyoming refinery.
As is typical of older small refineries like the Wyoming refinery, the largest cost component arising from these various decrees relates to the investigation, monitoring and remediation of soil, groundwater, surface water and sediment contamination associated with the facility’s historic operations. Investigative work by Wyoming Refining and negotiations with the relevant agencies as to remedial approaches remain ongoing on a number of aspects of the contamination, meaning that investigation, monitoring and remediation costs are not reasonably estimable for some elements of these efforts. Based on current information, however, preliminary estimates we have received for the well-understood components of these efforts suggest total response costs of approximately $18.0 million, approximately one-third of which we expect to incur in the next five years and the remainder being incurred over approximately 30 years.
Additionally, we believe the Wyoming refinery will need to modify or close a series of wastewater impoundments in the next several years and to replace those impoundments with a new wastewater treatment system. Based on preliminary information, reasonable estimates we have received suggest costs of approximately $0.5 million to modify or close the existing wastewater treatment ponds and approximately $11.6 million to design and construct a new wastewater treatment system.
Finally, among the various historic consent decrees, orders and settlement agreements into which the Wyoming refinery has entered, there are several penalty orders associated with exceedances of permitted limits by the Wyoming refinery’s wastewater discharges. Although the frequency of these exceedances appears to be declining over time, we may become subject to new penalty enforcement action in the next several years, which could involve penalties in excess of $100,000. Moreover, in addition to the issues associated with the Wyoming refinery, certain product pipeline assets were acquired in the WRC Acquisition. The Pipeline and Hazardous Materials Administration (“PHMSA”) conducted an integrated inspection of the products pipeline in November 2016 with additional follow-up regarding integrity management planning and general operations and maintenance. Based on preliminary discussions with PHMSA following this inspection, the Wyoming refinery anticipates a civil penalty in excess of $100,000. In connection with our acquisition of, and commencement of operations at, the Wyoming refinery, findings of a past failure to comply with applicable environmental or pipeline safety laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties that could be in excess of $100,000, the imposition of investigatory, remedial or corrective actions and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations.

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The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to manage risks associated with our businesses and increase the working capital requirements to conduct these activities.
The Dodd-Frank Act, which was passed by the U.S. Congress and signed into law in July 2010, provides for new statutory and regulatory requirements for derivative transactions, including crude oil and natural gas derivative transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the Dodd-Frank Act. In October 2011, the CFTC approved final rules that established position limits for futures contracts on 28 physical commodities. These initial CFTC position limits rules were vacated by the U.S. District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
It is not possible at this time to predict with certainty the full effect of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act may require us to comply with margin requirements and with certain clearing and trade-execution requirements if we do not satisfy certain specific exceptions. Although we expect to qualify for the end-user exception to the clearing, trade execution and margin requirements for swaps entered to hedge our commodity risks, the application of the requirements to other market participants, such as swap dealers, may change the cost and availability of our derivatives. Depending on the rules adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities derivative transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures. A requirement to post cash collateral could therefore reduce our ability to execute transactions to reduce commodity price risk and thus protect cash flows.
The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until all of the regulations are implemented. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable. In addition, the Dodd-Frank Act was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices.
In addition, the European Union and other non‑U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.
BUSINESS RISKS
The locations of our refineries and related assets in the Hawaiian Islands and in Newcastle, Wyoming, creates an exposure to the risks of the local economies in which we operate and other local adverse conditions. Additionally, the location of our Hawaii refinery creates the risk of lower margins should the supply/demand balance change in the Hawaiian Islands requiring that we deliver refined products to customers outside of the region.
Because of the locations of our two refineries in Hawaii and Wyoming, we primarily market our refined products in relatively limited geographic areas. As a result, we are more susceptible to regional economic conditions than the operations of more geographically diversified competitors and any unforeseen events or circumstances that affect our operating area could also materially adversely affect our revenues and our business and operating results. These factors include, among other things, changes in the economy, weather conditions, demographics and population, increased supply of refined products from competitors and reductions in the supply of crude oil.
Additionally, should the supply and demand balance shift in Hawaii, resulting in supply on the islands exceeding demand, we may have to deliver refined products to customers off-island. These sales generally result in lower margins to us relative to on-island sales given the higher cost of freight and typically lower price points.

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We must make substantial capital expenditures at our refineries and related assets to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows could be adversely affected.
Our refineries and related assets have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep the refineries operating at optimum efficiency. These costs do not result in increases in unit capacities, but rather are focused on trying to maintain safe, reliable operations.
Delays or cost increases related to the engineering, procurement and construction of new facilities, or improvements and repairs to our existing facilities and equipment, could have a material adverse effect on our business, financial condition, or results of operations. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:
denial or delay in obtaining regulatory approvals and/or permits;
difficulties in executing the capital projects;
unplanned increases in the cost of equipment, materials or labor;
disruptions in transportation of equipment and materials;
severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of our 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
non-performance or force majeure by, or disputes with, our vendors, suppliers, contractors or sub-contractors.
Any one or more of these occurrences noted above could have a significant impact on our business. If we were unable to make up the delays or to recover the related costs, or if market conditions change, it could materially and adversely affect our financial position, or results of operations or cash flows.
If we are unable to obtain our crude oil supply for our Hawaii refinery without the benefit of our Supply and Offtake Agreements with J. Aron, the capital required to finance our crude oil supply could negatively impact our liquidity.
All of the crude oil delivered at our Hawaii refinery is subject to our Supply and Offtake Agreements with J. Aron. If we are unable to obtain our crude oil supply for our Hawaii refinery outside these agreements, our exposure to crude oil pricing risks may increase as the number of days between when we pay for the crude oil and when the crude oil is delivered to us increases. Such increased exposure could negatively impact our liquidity position due to the increase in working capital used to acquire crude oil inventory for our Hawaii refinery.
The ongoing work related to the Consent Decree subjects us to risks associated with engineering, procurement and construction of improvements and repairs to our facilities, related penalties and fines and the performance of equipment, all of which could have a material adverse effect on our business, financial condition or results of operations.
On July 18, 2016, PHR and subsidiaries of Tesoro entered into the Consent Decree. As a result of the Consent Decree, PHR expanded its previously-announced 2016 Hawaii refinery turnaround to undertake additional capital improvements to reduce emissions of air pollutants and to provide for certain NOx and SO2 emission controls and monitoring required by the Consent Decree. Although the turnaround was completed during the third quarter of 2016, work related to the Consent Decree is ongoing and the parties continue to work together to address the EPA's requirements. This work subjects us to risks associated with engineering, procurement and construction of improvements and repairs to our facilities and related penalties and fines to the extent applicable deadlines under the Consent Decree are not satisfied, as well as risks related to the performance of equipment required by, or affected by, the Consent Decree. Each of these risks could have a material adverse effect on our business, financial condition, or results of operations.
Our arrangement with J. Aron exposes us to J. Aron-related credit and performance risk.
We have Supply and Offtake Agreements with J. Aron, pursuant to which J. Aron will intermediate crude oil supplies and refined product inventories at our Hawaii refinery. J. Aron will own all of the crude oil in our tanks and substantially all of our refined product inventories prior to our sale of the inventories. Upon termination of the Supply and Offtake Agreements, which may be terminated by J. Aron as early as May 31, 2018, we are obligated to repurchase all crude oil and refined product inventories then owned by J. Aron and located at the specified storage facilities at then current market prices. Relying on J. Aron’s ability to honor its supply and offtake obligations exposes us to J. Aron’s credit and business risks. An adverse change in J. Aron’s business, results of operations, liquidity or financial condition could adversely affect its ability to perform its obligations, which could consequently have a material adverse effect on our business, results of operations or liquidity and, as a result, our business and operating results. In addition, we may be required to use substantial capital to repurchase crude oil and refined product inventories

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from J. Aron upon termination of the agreements, which could have a material adverse effect on our business, results of operations or financial condition.
Our retail business is vulnerable to risks including changes in consumer preferences and economic conditions, competitive environment, supplier concentration and other trends and factors that could harm our business, financial condition and results of operations.
Our retail business is subject to changes in consumer preferences, national, regional and local economic conditions, demographic trends and consumer confidence in the economy. Factors such as traffic patterns, weather conditions, local demographics and the number and locations of competing fueling stations and convenience stores also affect the performance of our retail stores. Adverse changes in any of these trends or factors could reduce our retail customer traffic or sales, or impose limits on our pricing that could adversely affect our business, financial condition and results of operations.
We cannot be certain that our net operating loss tax carryforwards will continue to be available to offset our tax liability.
As of December 31, 2016, we estimated that we had approximately $1.6 billion of net operating loss tax carryforwards ("NOLs"). In order to utilize the NOLs, we must generate taxable income that can offset such carryforwards. The availability of NOLs to offset taxable income would be substantially reduced or eliminated if we were to undergo an “ownership change” within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”). We will be treated as having had an “ownership change” if there is more than a 50% increase in stock ownership during any three year “testing period” by “5% shareholders.” 
In order to help us preserve our NOLs, our certificate of incorporation contains stock transfer restrictions designed to reduce the risk of an ownership change for purposes of Section 382 of the Code. We expect that the restrictions will remain in place for the foreseeable future. We cannot assure you, however, that these restrictions will prevent an ownership change.
The NOLs will expire in various amounts, if not used, between 2027 through 2035. The Internal Revenue Service (“IRS”) has not audited any of our tax returns for any of the years during the carryforward period including those returns for the years in which the losses giving rise to the NOLs were reported. We cannot assure you that we would prevail if the IRS were to challenge the availability of the NOLs. If the IRS were successful in challenging our NOLs, all or some portion of the NOLs would not be available to offset any future consolidated income which would negatively impact our results of operations and cash flows.
Inadequate liquidity could materially and adversely affect our business operations in the future.
If our cash flow and capital resources are insufficient to fund our obligations, we may be forced to reduce our capital expenditures, seek additional equity or debt capital or restructure our indebtedness. We cannot assure you that any of these remedies could, if necessary, be affected on commercially reasonable terms, or at all. Our liquidity is constrained by our need to satisfy our obligations under our credit agreements and our Supply and Offtake Agreements. The availability of capital when the need arises will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, the crack spread, natural gas and crude oil prices, our credit ratings, interest rates, market perceptions of us or the industries in which we operate, our market value and our operating performance. We may be unable to execute our long-term operating strategy if we cannot obtain capital from these or other sources when the need arises.
Our ability to generate cash and repay our indebtedness or fund capital expenditures depends on many factors beyond our control and any failure to do so could harm our business, financial condition and results of operations.
Our ability to fund future capital expenditures and repay our indebtedness when due will depend on our ability to generate sufficient cash flow from operations, borrowings under our credit agreements and distributions from our subsidiaries. To a certain extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions and other factors that are beyond our control, including the crack spread and the prices we receive for our natural gas and crude oil production.
We cannot assure you that our businesses will generate sufficient cash flow from operations, that our subsidiaries can or will make sufficient distributions to us or that future borrowings will be available to us in an amount sufficient to repay our indebtedness or fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our needs, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital or restructure our debt. We cannot assure you that any of these remedies could, if necessary, be affected on commercially reasonable terms, or at all, which could cause us to default on our obligations and could impair our liquidity.
Covenants in our existing debt agreements limit our ability to undertake certain types of transactions and may limit our ability to extract value from our subsidiaries.

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Our existing credit agreements contain certain negative covenants that limit our ability to undertake certain types of transactions, as well as restrictive financial covenants that require us to maintain compliance with specified financial ratios. We may have to modify or curtail some of our operations to maintain compliance with the covenants in these agreements. These covenants may also limit our ability to extract value from our operating subsidiaries. A violation of any of these covenants could result in a default under our credit agreements, which could permit our lenders to accelerate the repayment of any borrowings then outstanding.  A default or acceleration under our credit agreements would result in increased capital costs and could adversely affect our ability to operate our business, our results of operations and our financial condition.
Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations and limit our ability to react to changes in the economy or our industry.
We have, and will continue to have, a significant amount of indebtedness. Our obligation to repay our existing indebtedness will limit our ability to use our capital for other purposes. We may also incur additional indebtedness, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop our businesses to the extent desired. A higher level of indebtedness and/or the issuance of preferred stock would increase the risk that we may default on our obligations. Our ability to meet our indebtedness depends on our future performance. General economic conditions, the crack spread, natural gas and crude oil prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors that will affect our ability to raise cash through an offering of securities or a refinancing of our indebtedness include financial market conditions, the value of our assets and our performance at the time we need capital.
We may incur losses and incur additional costs as a result of our forward-contract activities and derivative transactions.
We enter into derivative contracts from time to time primarily to reduce our exposure to fluctuations in interest rates and in the price of crude oil and refined products. If the instruments we use to hedge our exposure are not effective, or if our counterparties are unable to satisfy their obligations to us, we may incur losses. The risk of counterparty default is heightened in a poor economic environment. We may also be required to incur additional costs in connection with future regulation of derivative instruments to the extent such regulation is applicable to us. Additionally, our commodity derivative activities may produce significant period-to-period earnings volatility that is not necessarily reflective of our underlying operational performance.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
We are subject to interest rate risk in connection with borrowings under certain of our credit facilities, which bear interest at variable rates. Interest rate changes will not affect the market value of indebtedness incurred under such facilities, but could affect the amount of our interest payments and, accordingly, our future earnings and cash flows, assuming other factors are held constant. A significant increase in prevailing interest rates that results in a substantial increase in the interest rates applicable to our indebtedness could substantially increase our interest expense and have a material adverse effect on our financial condition, results of operations and cash flows.
Increases in interest rates could adversely impact our ability to incur indebtedness for acquisitions or other purposes.
We have historically incurred indebtedness to fund our acquisitions and other working capital needs. Interest rates may increase in the future and, as a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. A rising interest rate environment could have an adverse impact, as a result of such increased financing costs, on our ability to incur indebtedness for acquisitions or other purposes.
We may be unable to successfully identify, execute or effectively integrate future acquisitions, which may negatively affect our results of operations.
We will continue to pursue acquisitions in the future. Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition or, if the acquisition occurs, effectively integrate the acquired business into our existing businesses. Negotiations of potential acquisitions and the integration of acquired business operations may require a disproportionate amount of management’s attention and our resources. Even if we complete additional acquisitions, continued acquisition financing may not be available or available on reasonable terms, any new businesses may not generate the anticipated level of revenues, the anticipated cost efficiencies or synergies may not be realized and these businesses may not be integrated successfully or operated profitably. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our results of operations.

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We may be unable to compete effectively with larger companies for acquisitions, which could have a material adverse effect on our businesses, results of operations and financial condition.
The industries in which we operate are intensely competitive and we compete with other companies that have greater resources than we have. Our ability to acquire additional businesses or properties in the future will be dependent upon our ability to evaluate and select suitable businesses or properties for acquisition and to consummate transactions in a highly competitive environment. Many of our larger competitors have refining operations, market petroleum and other products and explore for and produce natural gas and crude oil on a regional, national or worldwide basis. These companies may be able to pay more for acquisition targets, or evaluate or bid for and purchase a greater number of acquisition targets, than our resources permit. Our inability to compete effectively with larger companies for acquisitions could have a material adverse effect on our business, results of operations and financial condition.
Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating potential liabilities.
Our recent growth is due in large part to acquisitions, such as the acquisitions of Texadian, PHR, Mid Pac and the WRC Acquisition. We expect acquisitions to be instrumental to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of potential unknown and contingent liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform due diligence reviews of acquired companies and their businesses that we believe are generally consistent with industry practices. However, such reviews will not reveal all existing or potential problems. In addition, our reviews may not permit us to become sufficiently familiar with potential environmental problems or other contingent and unknown liabilities that may exist or arise. As a result, there may be unknown and contingent liabilities related to acquired businesses of which we are unaware. We could be liable for unknown obligations relating to acquisitions for which indemnification is not available, which could materially adversely affect our business, results of operations and cash flows.
We may fail to successfully integrate Wyoming Refining with our existing business in a timely manner, which could have a material adverse effect on our business, financial condition, results of operations or cash flows, or fail to realize all of the expected benefits of the WRC Acquisition, which could negatively impact our future results of operations and financial condition.
Integration of Wyoming Refining with our existing business has been, and will continue to be, a complex, time-consuming and costly process, particularly given that the acquisition of Wyoming Refining significantly increased our size and diversified the geographic areas in which we operate. A failure to successfully integrate Wyoming Refining with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash flows. The difficulties of combining Wyoming Refining with our existing business include, among other things:
operating a larger combined organization and adding operations;
difficulties in the assimilation of the assets and operations of Wyoming Refining;
customer or key employee loss from Wyoming Refining;
the diversion of management’s attention from other business concerns;
integrating personnel from diverse business backgrounds and organizational cultures;
managing relationships with new customers and suppliers for whom we have not previously provided products or services;
maintaining an effective system of internal controls related to Wyoming Refining and integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other regulatory compliance and corporate governance matters;
an inability to complete other internal growth projects and/or acquisitions;
difficulties integrating new technology systems that we have not historically used in our operations or financial reporting;
an increase in our indebtedness;
potential environmental or regulatory compliance matters or liabilities and title issues, including certain liabilities arising from Wyoming Refining's operations before our acquisition of Wyoming Refining;
coordinating geographically disparate organizations, systems and facilities; and
coordinating and consolidating corporate and administrative functions.
If any of these risks or unanticipated liabilities or costs were to materialize, then any desired benefits of the acquisition of Wyoming Refining may not be fully realized, if at all, and our future results of operations could be negatively impacted. In addition, the Wyoming Refining business may actually perform at levels below the forecasts we used to evaluate the acquisition of Wyoming Refining due to factors that are beyond our control, such as competition in Wyoming Refining's region, market demand for the products Wyoming Refining produces and regulatory requirements for maintenance and improvement projects that impact Wyoming Refining. If Wyoming Refining performs at levels below the forecasts we used to evaluate the acquisition of Wyoming Refining, then our future results of operations and financial condition could be negatively impacted.

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Wyoming Refining is scheduled for a maintenance turnaround during 2019 and 2020 that will involve significant expenditures.
Wyoming Refining expects to perform a significant maintenance turnaround at the Wyoming refinery during 2019 and 2020. All or a portion of its refinery’s production may be halted or disrupted during the turnaround and the turnaround, if unsuccessful or delayed, could have a material adverse effect on our business, financial condition or results of operations.
In addition, the Wyoming refinery may require additional unscheduled down time for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds. Refinery operations may also be disrupted by external factors such as a suspension of feedstock deliveries or an interruption of electricity, natural gas, water treatment or other utilities. Other potentially disruptive factors include natural disasters, severe weather conditions, workplace or environmental accidents, interruptions of supply, work stoppages, losses of permits or authorizations or acts of terrorism. Disruptions to our refining operations could reduce our revenues during the period of time that our processing units are not operating.
If our goodwill or intangible assets become impaired we may be required to record a significant charge to earnings.
Under U.S. GAAP, we review our intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. Goodwill is required to be tested for impairment at least annually. Factors that may be considered when determining if the carrying value of our goodwill or intangible assets may not be recoverable include a significant decline in our expected future cash flows or a sustained, significant decline in our stock price and market capitalization.
As a result of our acquisitions, we have significant goodwill and intangible assets recorded on our balance sheet. In addition, significant negative industry or economic trends, such as those that have occurred as a result of the recent economic downturn, including reduced estimates of future cash flows or disruptions to our business could indicate that goodwill or intangible assets might be impaired. If, in any period our stock price decreases to the point where our market capitalization is less than our book value, this too could indicate a potential impairment and we may be required to record an impairment charge in that period. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on projections of future operating performance. We operate in highly competitive environments and projections of future operating results and cash flows may vary significantly from actual results. As a result, we may incur substantial impairment charges to earnings in our financial statements should an impairment of our goodwill or intangible assets be determined resulting in an adverse impact on our results of operations.
A substantial portion of our refining workforce is unionized and we may face labor disruptions that would interfere with our operations.
As of December 31, 2016, we employed approximately 863 people, with a collective bargaining agreement covering about 141 of those employees. The union ratified a four-year extension of the collective bargaining agreement on March 23, 2015. On January 13, 2016, a claim against us was brought to the United States National Labor Relations Board alleging a refusal to bargain collectively and in good faith. Accordingly, we may not be able to prevent a strike or work stoppage in the future and any such work stoppage could cause disruptions in our business and have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our disclosure controls and procedures may not prevent or detect all acts of fraud.
Our disclosure controls and procedures are designed to reasonably assure that information required to be disclosed by us in reports we file or submit under the Exchange Act is accumulated and communicated to management, recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Our management, including our Chief Executive Officer and Chief Financial Officer, believes that any disclosure controls and procedures or internal controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, they cannot provide absolute assurance that all control issues and instances of fraud, if any, within our companies have been prevented or detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people or by an unauthorized override of the controls. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events and we cannot assure you that any design will succeed in achieving its stated goals under all potential future conditions. Accordingly, because of the inherent limitations in a cost effective control system, misstatements due to error or fraud may occur and may not be detected.

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Adverse changes in global economic conditions and the demand for transportation fuels may impact our business and financial condition in ways that we currently cannot predict.
The economic recovery from the recent recession continues to be tenuous and the risk of further significant global economic downturn remains. Further prolonged downturns or failure to recover could result in declines in consumer and business confidence and spending as well as increased unemployment and reduced demand for transportation fuels. This would adversely affect the business and economic environment in which we operate. These conditions increase the risks associated with the creditworthiness of our suppliers, customers and business partners. The consequences of such adverse effects could include interruptions or delays in our suppliers’ performance of our contracts, reductions and delays in customer purchases, delays in or the inability of customers to obtain financing to purchase our products and bankruptcy of customers. Any of these events may adversely affect our cash flows, profitability and financial condition.
Adverse results of legal proceedings could materially adversely affect us.
We may be subject to a variety of legal proceedings and claims that arise out of the ordinary conduct of our business. Results of legal proceedings cannot be predicted with certainty. Regardless of its merits, litigation may be both lengthy and disruptive to the company’s operations and may cause significant expenditures and diversion of management attention. We may be faced with significant monetary damages or injunctive relief that could materially adversely affect our business operations or materially and adversely affect our financial position and results of operations should we fail to prevail in certain matters.
Competition from integrated national and international oil companies that produce their own supply of feedstocks, from importers of refined products and from high volume retailers and large convenience store retailing operators who may have greater financial resources, could materially affect our business, financial condition and results of operations.
We compete with a number of integrated national and international oil companies who produce crude oil, some of which is used in their refining operations. Unlike these oil companies, we must purchase all of our crude oil from unaffiliated sources. Because these oil companies benefit from increased commodity prices, have greater access to capital and have stronger capital structures, they are able to better withstand poor and volatile market conditions, such as a lower refining margin environment, shortages of crude oil and other feedstocks or extreme price fluctuations.
We face strong competition in the fuel and convenience store retailing market for the sale of retail gasoline and convenience store merchandise. Our competitors include service stations operated by integrated major oil companies and well-recognized national high-volume retailers and regional large chain convenience store operators, often selling gasoline or merchandise at aggressively competitive prices.
Some of these competitors may have access to greater financial resources, which may provide them with a better ability to bear the economic risks inherent in all phases of our industry. Fundamental changes in the supply dynamics of foreign product imports could lead to reduced margins for the refined products we market, which could have an adverse effect on the profitability of our business.
RISKS RELATED TO OUR COMMON STOCK
Because we have no near term plans to pay cash dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.
We have never declared or paid any cash dividends on our common stock. We currently intend to retain all available funds and any future earnings for use in the operation and expansion of our business and do not anticipate declaring or paying any cash dividends on our common stock in the near term. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend on then-existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our board of directors considers relevant.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock is influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

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The price of our common stock historically has been volatile. This volatility may affect the price at which you could sell your common stock.
The market price for our common stock has varied between a high of $24.11 on January 29, 2016, and a low of $12.18 on September 1, 2016, during the year ended December 31, 2016. This volatility may affect the price at which you could sell your common stock. Our stock price is likely to continue to be volatile and subject to significant price and volume fluctuations in response to market and other factors; variations in our quarterly operating results from our expectations or those of securities analysts or investors; downward revisions in securities analysts’ estimates; and announcement by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments.
The market for our common stock has been historically illiquid, which may affect your ability to sell your shares.
The volume of trading in our common stock has historically been low. In addition, a substantial amount of our common stock is held by two investors who have restrictions on their ability to sell the stock. The lack of substantial liquidity can adversely affect the price of our stock at a time when you might want to sell your shares. There is no guarantee that an active trading market for our common stock will develop or be maintained on the NYSE MKT, or that the volume of trading will be sufficient to allow for timely trades. Investors may not be able to sell their shares quickly or at the latest market price if trading in our stock is not active or if trading volume is limited. In addition, if trading volume in our common stock is limited, trades of relatively small numbers of shares may have a disproportionate effect on the market price of our common stock.
Delaware law, our charter documents and concentrated stock ownership may impede or discourage a takeover, which could reduce the market price of our common stock.
We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders. For example, the change in ownership limitations contained in Article 11 of our certificate of incorporation could have the effect of discouraging or impeding an unsolicited takeover proposal. In addition, our board of directors or a committee thereof has the power, without stockholder approval, to designate the terms of one or more series of preferred stock and issue shares of preferred stock. The ability of our board of directors or a committee thereof to create and issue a new series of preferred stock and certain provisions of Delaware law and our certificate of incorporation and bylaws could impede a merger, takeover or other business combination involving us or discourage a potential acquirer from making a tender offer for our common stock, which, under certain circumstances, could reduce the market price of our common stock.
Zell Credit Opportunities Master Fund, L.P. (“ZCOF”) and Whitebox Advisors, LLC (“Whitebox”), together with their respective affiliates, each own or have the right to acquire as of February 24, 2017 approximately 28.7% and 15.7%, respectively, of our outstanding common stock. The level of their combined ownership of shares of our common stock could have the effect of discouraging or impeding an unsolicited acquisition proposal.
We may issue preferred stock with terms that could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could adversely affect the residual value of the common stock.
We may issue shares of common stock in satisfaction of general unsecured claims from our predecessor’s bankruptcy that would dilute your ownership of our common stock.
In December 2011 and January 2012, Delta Petroleum Corporation and its subsidiaries filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware, and in March 2012, obtained approval from the bankruptcy court to proceed with a plan of reorganization. Pursuant to this plan, among other things, certain allowed general unsecured claims may be paid with shares of our common stock. As of December 31, 2016, two claims totaling approximately $22.4 million remain to be resolved and we have reserved approximately $0.5 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at period end. The settlement of claims is subject to ongoing litigation and we are unable to predict with certainty how many shares will be required to satisfy all claims. Pursuant to the plan of reorganization, allowed claims are settled at a ratio of 54.4 shares per $1,000 of claim. Any issuances by us of

34




common stock to satisfy claims would have a dilutive impact on the ownership interest of existing common stockholders and could cause the market price of our common stock to decline.
Future sales of our common stock could reduce our stock price and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
We are not restricted from issuing additional shares of common stock, including shares issuable pursuant to securities that are convertible into or exchangeable for, or that represent the right to receive, common stock. We have approximately 45.5 million shares of common stock outstanding as of February 24, 2017.
Subject to the satisfaction of vesting conditions and the requirements of Rule 144 of the Securities Act, shares of our common stock registered under our equity incentive plan are available for resale immediately in the public market without restriction. In addition, subject to the change in ownership limitations contained in Article 11 of our certificate of incorporation, up to 7,722,809 shares of our common stock registered under our registration statements on Form S-3, declared effective on November 30, 2016 and December 21, 2016, are available for resale immediately in the public market without restriction.
We cannot predict the size of future issuances of our common stock or securities convertible into or exchangeable for, or that represent the right to receive, common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
Item  1B. UNRESOLVED STAFF COMMENTS
None.
Item  2. PROPERTIES
Please read “Item 1. — Business” of this Form 10-K for the location and general character of the properties used in our refining, retail and logistics segments. Our corporate headquarters are located at 800 Gessner Road, Suite 875, Houston, Texas, 77024. We believe that these properties and facilities are adequate for our operations and are maintained in a good state of repair.
Natural Gas and Oil Properties
Laramie Energy 
All of the assets held by Laramie Energy are located in Garfield, Mesa and Rio Blanco Counties, Colorado. All of the natural gas and crude oil reserves associated with such assets are produced primarily from the Mesaverde Formation and to a lesser extent the Mancos Formation and some of the acreage is contiguous. The geology of the Piceance Basin is characterized as highly consistent and predictable over large areas, which generally equates to reliable timing and cost expectations during drilling and completion activities, as well as minimal well-to-well variance in production and reserves when completed with the same methodology. Laramie Energy considers the Mesaverde Formation within Garfield, Mesa and Rio Blanco Counties, Colorado, to be a single field. Laramie and its predecessor company have drilled over 300 natural gas wells with over a 99% success rate in the Piceance Basin. 
Other 
We have a carried 3.3% to 4.5% working interest in 22 wells in the southern region of the Piceance Basin. These wells are operated by Encana Corporation. We also have overriding royalty interests in 12 wells located in Eddy County, New Mexico. Our interest in these wells varies from .32% to 2.5%. These wells are operated by Mewbourne Oil Company. On March 23, 2016, we entered into a settlement agreement with Whiting Oil and Gas Corporation (“Whiting”), whereby we paid Whiting an aggregate of $3.9 million to transfer the entirety of our interest in the Point Arguello Unit offshore California (“Point Arguello”) to Whiting and to satisfy any and all obligations in respect of such interest in Point Arguello.
Reserves
For a table presenting the estimated natural gas and crude oil reserves we own indirectly through Laramie Energy, please read “Item 1. — Business — Natural Gas and Oil” of this Form 10-K. The natural gas and crude oil reserves we own directly are not material.

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Internal Controls Over Reserve Estimates, Technical Qualifications and Technologies Used
Our policies regarding internal controls over reserve estimates require reserves to be in compliance with the SEC definitions and guidance and for all reserve estimates to be prepared by an independent third-party reserve engineering firm and reviewed by certain members of senior management. As we do not operate our interests in our natural gas and crude oil assets, we do not have an internal reserve engineering staff and do not prepare any internal reserve estimates. Christopher Micklas, our chief financial officer, reviews the independence and professional qualifications of the third-party engineering firms we engage. He also supervises the submission of technical and financial data to third-party engineering firms and reviews the prepared reports. Mr. Micklas has more than 12 years of experience in senior financial positions in the oil and gas industry. The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Benjamin W. Johnson and Mr. John G. Hattner. Mr. Johnson, a Licensed Professional Engineer in the State of Texas (No. 124738), has been practicing consulting petroleum engineering at NSAI since 2007 and has over two years of prior industry experience. He graduated from Texas Tech University in 2006 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geology (License No. 559), has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 11 years of prior industry experience. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary’s College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The professional qualifications of the individuals at NSAI who were responsible for overseeing the preparation of our reserve estimates as of December 31, 2016 have been filed as part of Exhibit 99.1 to this Annual Report on Form 10-K. 
A variety of methodologies were used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, analog type curve analysis, log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. 
Production Volumes, Unit Prices and Costs 
All of Laramie Energy's properties are located in Garfield, Mesa and Rio Blanco Counties, Colorado. Over 90% of Laramie Energy's total estimated proved reserves are located in the same geological formation, the Mesaverde Formation, which Laramie Energy considers to be a single field.

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The following table sets forth certain information regarding volumes of production sold and average prices received associated with our share of Laramie Energy's production and sales of natural gas and crude oil for the years ended December 31, 2016, 2015 and 2014.
 
 
Year Ended December 31,
Company's share of Laramie Energy:
2016
 
2015
 
2014
Production volumes:
 
 
 
 
 

Oil (Mbbls)
59

 
20

 
18

NGLs (Mbbls)
552

 
149

 
125

Natural Gas (MMcf)
15,192

 
4,745

 
4,831

Total (MMcfe)
18,857

 
5,759

 
5,689

Net average daily production:
 
 
 
 
 

Oil (Bbls)
160

 
55

 
49

NGLs (Bbls)
1,508

 
408

 
342

Natural Gas (Mcf)
41,509

 
13,000

 
13,236

Average sales price:
 
 
 
 
 

Oil (Per Bbl)
$
37.85

 
$
38.46

 
$
80.98

NGLs (Per Bbl)
11.61

 
11.76

 
34.73

Natural Gas (per Mcf)
2.30

 
2.47

 
4.35

Hedge gain (loss) (per Mcfe)
(1.47
)
 
0.33

 
0.36

Lease operating costs (per Mcfe)
0.45

 
0.56

 
0.48

The table above excludes production volumes related to our other non-operated natural gas and oil interests of 67 MMcfe, 311 MMcfe and 716 MMcfe for the years ended December 31, 2016, 2015 and 2014, respectively. Please read Note 22—Supplemental Oil and Gas Disclosures (Unaudited) to our consolidated financial statements under Item 8 of this Form 10-K for further information on our proved reserves related to other non-operated natural gas and oil interests.
Proved Undeveloped Reserves
All of our proved undeveloped reserves at December 31, 2016 are held through our minority equity ownership in Laramie Energy. We do not control Laramie Energy and therefore cannot predict or control the development of the properties.
As of December 31, 2016, our share of Laramie Energy’s proved undeveloped reserves totaled 197,488 MMcfe, an approximate 140% increase from proved undeveloped reserves at December 31, 2015. This increase was primarily due to Laramie Energy's acquisition of properties in the Piceance Basin for $157.5 million in March 2016 and wells that have become economic as a result of increased operator efficiency and cost reductions.
As of December 31, 2016, approximately 5% of our share of Laramie Energy’s proved undeveloped reserves (approximately 10,591 MMcfe) were scheduled for development more than five years after initial booking.  Based on supplied drilling and completion schedules, we expect all of Laramie Energy's proved undeveloped reserves at December 31, 2016 to be developed within 5 years of initial booking.
Laramie Energy is currently running one drilling rig performing multi-well pad drilling in the Mesaverde Formation.  To develop the remaining 361 proved undeveloped locations, Laramie Energy is forecasting increasing the number of rigs to levels previously used. The rigs are expected to drill a mix of both proved undeveloped and probable reserves locations in a program or “manufacturing” style process.  Current drill times are averaging 5.4 days per well, or 5.6 wells per month, and the typical pad will contain 16-22 wells.
The following table provides information regarding changes in our share of Laramie Energy's proved undeveloped reserves for the year ended December 31, 2016.

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Gas
 
Oil
 
NGLs
 
Total
 
(MMcf)
 
(Mbbl)
 
(Mbbl)
 
(MMcfe)
Proved undeveloped reserves at December 31, 2015
68,054

 
255

 
2,114

 
82,268

Revisions of previous estimates
38,446

 
81

 
987

 
44,854

Extensions and discoveries
638

 
1

 
19

 
758

Acquisitions
60,215

 
173

 
1,580

 
70,733

Conversion to proved developed reserves
(945
)
 
(2
)
 
(28
)
 
(1,125
)
Proved undeveloped reserves at December 31, 2016
166,408

 
508

 
4,672

 
197,488

Productive Wells and Acreage 
The table below shows, as of December 31, 2016, our share of Laramie Energy's gross and net wells and developed acres. Developed acreage consists of acres spaced or assignable to productive wells. 
 
 
Productive Wells
 
 
 
 
 
 
Oil 
 
Gas (1)
 
Developed Acres
Location
 
Gross (2)
 
Net (3)
 
Gross (2)
 
Net (3)
 
Gross (2)
 
Net (3)
Colorado (4)
 

 

 
1,586

 
671

 
20,671

 
8,744

_____________________________________________
(1)
Some of the wells classified as “gas” wells also produce minor amounts of crude oil.
(2)
A “gross well” or “gross acre” is a well or acre in which a working interest is held. The number of gross wells or acres is the total number of wells or acres in which a working interest is owned.
(3)
A “net well” or “net acre” is deemed to exist when the sum of fractional ownership interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof.
(4)
Net wells and net developed acres are reflected as if we owned our interest directly.
As of December 31, 2016, we also held interests in one productive gas well and 20 developed acres related to our other non-operated natural gas interests.
Undeveloped Acreage 
At December 31, 2016, our share of undeveloped acreage held through our ownership in Laramie Energy is set forth below: 
 
 
Undeveloped Acres (1) (2)
Location
 
Gross
 
Net
Colorado (3)
 
279,893

 
118,395

________________________________________________
(1)
Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and gas, regardless of whether such acreage contains proved reserves.
(2)
There are no material near-term lease expirations for which the carrying value at December 31, 2016 has not already been impaired in consideration of these expirations or capital budgeted to convert acreage to held by production.
(3)
Net undeveloped acres are reflected as if we owned our interest directly.
Drilling Activity 
Laramie Energy completed 56 natural gas wells during the year ended December 31, 2016 that were drilled during 2016 and prior years. During 2015, Laramie Energy completed 24 natural gas wells that were drilled during 2015 and prior years. During 2014, Laramie Energy completed 15 natural gas wells that were drilled during 2014 and prior years. The operators of our other natural gas and oil interests in Colorado and New Mexico did not drill any exploratory or development wells during 2016 and 2015. The operators of our other natural gas and oil interests in Colorado and New Mexico drilled two oil wells during 2014.
Delivery Commitments
Our natural gas and oil operations had no material delivery commitments as of December 31, 2016.
Item  3. LEGAL PROCEEDINGS
PHMSA Matters
The Pipeline and Hazardous Materials Administration (“PHMSA”) recently conducted an integrated inspection of the Wyoming refinery's products pipeline with additional follow-up regarding integrity management planning and general operations and maintenance. Based on preliminary discussions with PHMSA following this inspection, Wyoming Refining anticipates a civil penalty in excess of $100,000. In connection with our acquisition of, and commencement of operations at, the Wyoming refinery,

38




findings of a past failure to comply with applicable environmental or pipeline safety laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties that could be in excess of $100,000, the imposition of investigatory, remedial or corrective actions and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations.
Kawaihae Loading Rack
On October 9, 2014, Mid Pac received a notice from the EPA alleging that Mid Pac had violated the federal CAA at its terminal located in Kawaihae, Hawaii, by "failing to equip its loading rack with pollution controls" and by "failing to limit emissions from its loading rack," and advised Mid Pac that the matter had been referred to the DOJ. The DOJ proposed civil penalties of approximately $700 thousand. Subsequently, Mid Pac and the DOJ entered into a tolling agreement to facilitate settlement discussions. Mid Pac disputes the EPA's allegations. On April 1, 2015, we acquired Mid Pac. Mid Pac, the EPA and the DOJ agreed on September 6, 2016 to resolve the fines and penalties for $200 thousand and, among other things, the installation of a vapor combustion system.
Consent Decree
On July 18, 2016, PHR and subsidiaries of Tesoro entered into a consent decree with the EPA, the DOJ and other state governmental authorities concerning alleged violations of the federal CAA related to the ownership and operation of multiple facilities owned or formerly owned by Tesoro and its affiliates, including our Hawaii refinery. As a result of the Consent Decree, PHR expanded its previously-announced refinery turnaround completed during the third quarter of 2016 to undertake additional capital improvements to reduce emissions of air pollutants and to provide for certain NOx and SO2 emission controls and monitoring required by the Consent Decree. We estimate the cost of compliance with the Consent Decree to be approximately $30 million. However, Tesoro is responsible under the Environmental Agreement for reimbursing PHR for all reasonable third-party capital expenditures incurred for the Consent Decree to the extent related to acts or omissions prior to the date of the closing of the PHR acquisition. Tesoro is obligated to pay all applicable fines and penalties related to the Consent Decree.
Other
From time to time, we may be involved in other litigation relating to claims arising out of our operations in the normal course of our business. As of the date of this Annual Report on Form 10-K, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows. Any litigation pending at the time we emerged from Chapter 11 was transferred to the General Trust for resolution and settlement. For more information, please read “Item 1. — Business—Bankruptcy and Plan of Reorganization – General Recovery Trust” and Note 14—Commitments and Contingencies to our consolidated financial statements under Item 8 of this Form 10-K.
Item  4. MINE SAFETY DISCLOSURES
Not applicable.

39




PART II 
Item  5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Our common stock trades on the NYSE MKT under the symbol “PARR”. The high and low sale prices for our common stock for the most recent two fiscal years are shown in the table below.

Quarter Ended
 
High
 
Low
2016
 
 
 
 
December 31, 2016
 
$15.46
 
$12.47
September 30, 2016
 
$16.00
 
$12.18
June 30, 2016
 
$20.00
 
$13.90
March 31, 2016
 
$24.11
 
$17.48
2015
 
 
 
 
December 31, 2015
 
$28.31
 
$20.25
September 30, 2015
 
$21.50
 
$17.09
June 30, 2015
 
$25.67
 
$18.10
March 31, 2015
 
$23.38
 
$15.80
 
As of February 24, 2017, there were 176 common stockholders of record. On February 24, 2017, the closing price of our common stock was $14.53 per share on the NYSE MKT.
Dividends 
We have not paid dividends on our common stock and we do not expect to do so in the foreseeable future. Our current debt agreements restrict the payment of dividends. In addition, as long as any obligations remain outstanding under our Delayed Draw Term Loan, we are prohibited from paying dividends.
Stock Performance Graph
The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be deemed to be incorporated by reference into any future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended.

This performance graph and the related textual information are based on historical data and are not indicative of future performance. The following line graph compares the cumulative total return on an investment in our common stock against the cumulative total return of the S&P 500 Composite Index and an index of peer companies (that we selected) for the periods commencing September 1, 2012, the first day of trading of our common stock, through December 31, 2016. The performance graph of our peer group is weighted by market value at the beginning of the period and our peer group consists of the following companies: Alon USA Energy, Inc., Calumet Specialty Products Partners, L.P., Casey's General Stores, Inc., CVR Energy, Inc., Darling Ingredients Inc., Delek US Holdings, Inc., FutureFuel Corp., Green Plains Inc., Macquarie Infrastructure Corporation, Methanex Corporation, Pacific Ethanol, Inc., Renewable Energy Group, Inc., REX American Resources Corporation, SEACOR Holdings Inc., Stepan Company and Westlake Chemical Corporation. Axiall Corporation was excluded from our peer group because it was acquired by a third party during 2016. We believe our peer group, which is made up of oil and gas refining and marketing companies, retailers and companies that are generally similar to our operating segments provides for meaningful comparability to our business as a whole.

40




a2016123110_chart-33049.jpg
*$100 invested on September 5, 2012 in stock or August 31, 2012 in index, including reinvestment of dividends.
Recent Sales of Unregistered Securities 
During the year ended December 31, 2016, we did not have any sales of securities in transactions that were not registered under the Securities Act that have not been reported in a Form 8-K or Form 10-Q. 
Issuer Purchases of Equity Securities
The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended December 31, 2016:
Period
 
Total number of shares (or units) purchased (1)
 
Average price paid per share (or unit)
 
Total number of shares (or units) purchased as part of publicly announced plans or programs
 
Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs
October 1 - October 31, 2016
 
12,992

 
$
13.07

 

 

November 1 - November 30, 2016
 
3,485

 
14.76

 

 

December 1 - December 31, 2016
 
3,459

 
14.83

 

 

Total
 
19,936

 
$
13.67

 

 

________________________________________________
(1)
All shares repurchased were surrendered by employees to pay taxes withheld upon the vesting of restricted stock awards.

41




Item 6. SELECTED FINANCIAL DATA
The selected financial information presented below as of December 31, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014, was derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The selected financial information presented below as of December 31, 2014, 2013 and 2012 and for the year ended December 31, 2013, the period from September 1 through December 31, 2012, and the period from January 1 through August 31, 2012, was derived from our audited consolidated financial statements not included in this Annual Report on Form 10-K. The selected financial information should be read in conjunction with the consolidated financial statements and related notes and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
As a result of the application of fresh-start accounting as of September 1, 2012, following our reorganization, the financial statements on or prior to September 1, 2012 are not comparable with the financial statements after September 1, 2012. References to “Successor” refer to the Company after September 1, 2012, after giving effect to the application of fresh-start accounting. References to “Predecessor” refer to the Company on or prior to September 1, 2012.
 
 
Successor
 
 
Predecessor
(in thousands, except per share data)
 
Year Ended December 31, 2016 (1)
 
Year Ended December 31, 2015 (2)
 
Year Ended December 31, 2014
 
Year Ended December 31, 2013 (3)
 
September 1 through December 31, 2012
 
 
January 1 through August 31, 2012
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
1,865,045

 
$
2,066,337

 
$
3,108,025

 
$
886,014

 
$
2,144

 
 
$
23,079

Depreciation, depletion and amortization
 
31,617

 
19,918

 
14,897

 
5,982

 
401

 
 
16,041

Impairment expense
 

 
9,639

 

 

 

 
 
151,347

Trust litigation and settlements
 

 

 

 
6,206

 

 
 

Operating income (loss)
 
(16,494
)
 
61,514

 
(37,532
)
 
(47,405
)
 
(5,021
)
 
 
(170,677
)
Interest expense and financing costs, net
 
(28,506
)
 
(20,156
)
 
(17,995
)
 
(13,285
)
 
(1,056
)
 
 
(6,852
)
Loss on termination of financing agreements
 

 
(19,669
)
 
(1,788
)
 
(6,141
)
 

 
 

Change in value of common stock warrants
 
2,962

 
(3,664
)
 
4,433

 
(10,159
)
 
(4,280
)
 
 

Change in value of contingent consideration
 
10,770

 
(18,450
)
 
2,849

 

 

 
 

Equity earnings (losses) from Laramie Energy, LLC
 
(22,381
)
 
(55,983
)
 
2,849

 
(2,941
)
 
(1,325
)
 
 

Net loss
 
(45,835
)
 
(39,911
)
 
(47,041
)
 
(79,173
)
 
(8,839
)
 
 
(45,437
)
Loss per common share
 
(1.08
)
 
(1.06
)
 
(1.44
)
 
(4.01
)
 
(0.56
)
 
 
(1.57
)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
47,772

 
$
167,788

 
$
89,210

 
$
38,061

 
$
6,185

 
 
$
1,954

Total current assets
 
403,108

 
531,752

 
460,789

 
544,501

 
59,926

 
 
11,765

Total assets
 
1,145,433

 
892,261

 
735,236

 
801,271

 
189,582

 
 
210,389

Total current liabilities
 
382,765

 
365,040

 
310,806

 
453,388

 
69,977

 
 
352,859

Total long-term debt
 
350,110

 
154,212

 
101,739

 
79,872

 
7,391

 
 

Total liabilities
 
776,524

 
551,650

 
443,077

 
584,949

 
88,825

 
 
357,273

Total stockholders' equity
 
368,909

 
340,611

 
292,159

 
228,264

 
100,757

 
 
(146,884
)
_________________________________________________________
(1)
We completed the WRC Acquisition effective July 14, 2016, therefore, the results of WRC are only included subsequent to July 14, 2016. Please read Note 4—Acquisitions to the consolidated financial statements under Item 8 of this Form 10-K for further information.
(2)
We completed the acquisition of Mid Pac effective April 1, 2015, therefore, the results of Mid Pac are only included subsequent to April 1, 2015. Please read Note 4—Acquisitions to the consolidated financial statements under Item 8 of this Form 10-K for further information.
(3)
We completed the acquisition of PHR effective September 25, 2013, therefore, the results of PHR are only included subsequent to September 25, 2013. Please read Note 4—Acquisitions to the consolidated financial statements under Item 8 of this Form 10-K for further information.

42




Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We are a growth-oriented company based in Houston, Texas, that manages and maintains interests in energy and infrastructure businesses. We were created through the successful reorganization of Delta Petroleum Corporation ("Delta") in August 2012. The reorganization converted approximately $265 million of unsecured debt to equity and allowed us to preserve significant tax attributes. For more information, please read “Part I –Item 1. — Business—Overview” of this Form 10-K.
Recent Events
Hawaii Refinery Turnaround
During the third quarter of 2016, we successfully restarted our Hawaii refinery after a major turnaround and a maintenance project on our subsea pipeline. The turnaround and pipeline maintenance, including associated downtime and high feedstock costs, reduced our profitability. These higher costs were driven by higher-cost crude oil, additional imports of 8 thousand barrels per day in refined products during the turnaround, higher production costs per throughput barrel and $4.6 million in additional maintenance expense for the Hawaii refinery and subsea pipeline during the third quarter of 2016. The total deferred costs related to the turnaround were $32.7 million and will be amortized over the next three years.
Wyoming Refining Acquisition
On June 14, 2016, we entered into a unit purchase agreement (the “Purchase Agreement”) with Black Elk Refining, LLC to purchase all of the issued and outstanding units representing the membership interests in Hermes Consolidated, LLC (d/b/a Wyoming Refining Company) and indirectly Wyoming Refining Company’s wholly owned subsidiary, Wyoming Pipeline Company, LLC (collectively, “Wyoming Refining”) (the "WRC Acquisition"). Wyoming Refining owns and operates the 18 thousand barrels per day refinery and related logistics assets in Newcastle, Wyoming. We completed the WRC Acquisition on July 14, 2016, for cash consideration of $209.4 million, including a deposit of $5.0 million paid in June 2016 and assumed debt consisting of term loans of $58.0 million and revolving loans of $10.1 million. The consideration was paid with funds received from the issuance of our 2.50% convertible subordinated bridge notes (the "Bridge Notes"), cash on hand, which included the net proceeds from our issuance and sale of an aggregate of $115.0 million principal amount of 5.00% convertible senior notes due 2021 (the "5.00% Convertible Senior Notes"), and the issuance of a $65.0 million secured term loan by Par Wyoming Holdings, LLC (the "Par Wyoming Holdings Credit Agreement"). Please read Note 4—Acquisitions to our consolidated financial statements under Item 8 of this Form 10-K for further discussion.
Laramie Energy Contribution
On December 17, 2015, we entered into an equity commitment letter with Laramie Energy, pursuant to which we agreed to purchase certain membership interests of Laramie Energy for an aggregate cash purchase price of $55.0 million in connection with the closing of a purchase and sale agreement whereby Laramie Energy agreed to acquire certain properties in the Piceance Basin for $157.5 million, subject to customary purchase price adjustments. The transaction closed on March 1, 2016 and, upon the closing of the transaction, Laramie Energy assumed ownership and operatorship of the purchased properties and our ownership interest in Laramie Energy increased from 32.4% to 42.3%.
Factors Affecting Comparability
On April 1, 2015, we completed the acquisition of Mid Pac for cash consideration of $74.4 million. In connection with the acquisition, Mid Pac's pre-existing debt was fully repaid on the closing date for $45.3 million. The results of operations of Mid Pac are included in our segments effective April 1, 2015. Please read Note 4—Acquisitions to our consolidated financial statements under Item 8 of this Form 10-K for more information.    

43




Results of Operations
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Net Loss. During 2016, our financial performance was impacted by the turnaround at our Hawaii refinery and poor global crack spreads, which is reflected in an increase in our net loss from $39.9 million for the year ended December 31, 2015 to $45.8 million for the year ended December 31, 2016. Other factors impacting our results period over period include the termination of certain financing agreements in 2015, the change in value of our contingent consideration obligation, decreases in impairment expense and in our equity losses from Laramie Energy, an increase in interest expense and the releases of valuation allowances as further discussed below.
Adjusted EBITDA and Adjusted Net Income (Loss). For the year ended December 31, 2016, Adjusted EBITDA was $33.4 million compared to $110.4 million for the year ended December 31, 2015. The change was primarily related to higher production and maintenance costs associated with the turnaround at our Hawaii refinery and lower crack spreads, partially offset by improved crude oil differentials, the contribution provided by Wyoming Refining, which was acquired on July 14, 2016, and the full-year contribution provided by Mid Pac, which was acquired on April 1, 2015.
For the year ended December 31, 2016, Adjusted Net Income (Loss) was a loss of $49.8 million compared to income of $14.3 million for the year ended December 31, 2015. The change was primarily related to higher production and maintenance costs associated with the turnaround at our Hawaii refinery, lower crack spreads, higher interest expense and depreciation, depletion and amortization ("DD&A"), partially offset by improved crude oil differentials, a decrease in our equity losses from Laramie Energy, the contribution provided by Wyoming Refining, which was acquired on July 14, 2016, and the contribution provided by Mid Pac, which was acquired on April 1, 2015.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Net Loss. For the year ended December 31, 2015, our net loss was $39.9 million compared to a $47.0 million net loss for the year ended December 31, 2014. During the year ended December 31, 2015, we benefited from favorable market conditions with crack spreads above the five year average which improved our margins and declining crude oil prices which reduced our operating expenses. We continued the trend of commercial improvements with increased on-island sales mainly resulting from a contract with the military for jet fuel and additional fuel volumes as a result of our acquisition of Par Hawaii. The favorable market conditions were partially offset by losses related to the change in value of our common stock warrants and contingent consideration, equity losses from our investment in Laramie Energy and losses on the termination of financing agreements as further discussed below.
Adjusted EBITDA and Adjusted Net Income (Loss). For the year ended December 31, 2015, Adjusted EBITDA was $110.4 million compared to a $9.2 million loss for the year ended December 31, 2014. The change was primarily related to improved crack spreads and lower energy costs resulting from lower crude oil prices. For the year ended December 31, 2015, Adjusted Net Income (Loss) was $14.3 million compared to a $38.8 million loss for the year ended December 31, 2014. The change is primarily related to improved crack spreads and lower energy costs resulting from lower crude oil prices, offset by a decrease of $58.8 million in our equity earnings from Laramie Energy, largely due to an impairment of $41.1 million, higher DD&A expenses and higher interest expense and financing costs in 2015.

44




The following table summarizes our consolidated results of operations for the years ended December 31, 2016, 2015 and 2014. The following should be read in conjunction with our consolidated financial statements under Item 8 of this Annual Report on Form 10-K.
 
Year Ended December 31,
 
2016
 
2015
 
2014
Revenues
$
1,865,045

 
$
2,066,337

 
$
3,108,025

Cost of revenues (excluding depreciation)
1,636,339

 
1,787,368

 
2,937,472

Operating expense (excluding depreciation) (1)
166,216

 
141,621

 
146,573

Depreciation, depletion and amortization
31,617

 
19,918

 
14,897

Impairment expense

 
9,639

 

Loss on sale of assets, net

 

 
624

General and administrative expense
42,073

 
44,271

 
34,304

Acquisition and integration expense
5,294

 
2,006

 
11,687

Total operating expenses
1,881,539

 
2,004,823

 
3,145,557

Operating income (loss)
(16,494
)
 
61,514

 
(37,532
)
Other income (expense)
 
 
 
 
 
Interest expense and financing costs, net
(28,506
)
 
(20,156
)
 
(17,995
)
Loss on termination of financing agreements

 
(19,669
)
 
(1,788
)
Other income (expense), net
(98
)
 
(291
)
 
(312
)
Change in value of common stock warrants
2,962

 
(3,664
)
 
4,433

Change in value of contingent consideration
10,770

 
(18,450
)
 
2,849

Equity earnings (losses) from Laramie Energy, LLC
(22,381
)
 
(55,983
)
 
2,849

Total other expense, net
(37,253
)
 
(118,213
)
 
(9,964
)
Loss before income taxes
(53,747
)
 
(56,699
)
 
(47,496
)
Income tax benefit
7,912

 
16,788

 
455

Net loss
$
(45,835
)
 
$
(39,911
)
 
$
(47,041
)
________________________________________________________ 
(1)
Includes Lease operating expense, separately disclosed on our consolidated statements of operations.


45




The following tables summarize our operating income (loss) by segment for the years ended December 31, 2016, 2015 and 2014. The following should be read in conjunction with our consolidated financial statements under Item 8 of this Annual Report on Form 10-K.
Year ended December 31, 2016
 
Refining
 
Logistics (1)
 
Retail
 
Texadian
 
Corporate, Eliminations and Other (2)
 
Total
Revenues
 
$
1,702,463

 
$
102,779

 
$
290,402

 
$
41,064

 
$
(271,663
)
 
$
1,865,045

Cost of revenues (excluding depreciation)
 
1,580,014

 
65,439

 
220,545

 
42,079

 
(271,738
)
 
1,636,339

Operating expense (excluding depreciation)
 
112,724

 
11,239

 
41,291

 

 
815

 
166,069

Lease operating expense
 

 

 

 

 
147

 
147

Depreciation, depletion and amortization
 
17,565

 
4,679

 
6,372

 
667

 
2,334

 
31,617

General and administrative expense
 

 

 

 

 
42,073

 
42,073

Acquisition and integration expense
 

 

 

 

 
5,294

 
5,294

Operating income (loss)
 
$
(7,840
)
 
$
21,422

 
$
22,194

 
$
(1,682
)
 
$
(50,588
)
 
$
(16,494
)
Year ended December 31, 2015
 
Refining
 
Logistics (1)
 
Retail
 
Texadian
 
Corporate, Eliminations and Other (2)
 
Total
Revenues
 
$
1,895,662

 
$
82,671

 
$
283,507

 
$
132,472

 
$
(327,975
)
 
$
2,066,337

Cost of revenues (excluding depreciation)
 
1,718,729

 
48,660

 
215,194

 
134,780

 
(329,995
)
 
1,787,368

Operating expense (excluding depreciation)
 
95,588

 
5,433

 
35,317

 

 

 
136,338

Lease operating expense
 

 

 

 

 
5,283

 
5,283

Depreciation, depletion and amortization
 
9,522

 
3,117

 
5,421

 
854

 
1,004

 
19,918

Impairment expense
 

 

 

 
9,639

 

 
9,639

General and administrative expense
 

 

 

 

 
44,271

 
44,271

Acquisition and integration expense
 

 

 

 

 
2,006

 
2,006

Operating income (loss)
 
$
71,823

 
$
25,461

 
$
27,575

 
$
(12,801
)
 
$
(50,544
)
 
$
61,514

Year ended December 31, 2014
 
Refining
 
Logistics (1)
 
Retail
 
Texadian
 
Corporate, Eliminations and Other (2)
 
Total
Revenues
 
$
2,816,667

 
$
70,457

 
$
231,673

 
$
189,160

 
$
(199,932
)
 
$
3,108,025

Cost of revenues (excluding depreciation)
 
2,732,817

 
39,910

 
187,150

 
183,511

 
(205,916
)
 
2,937,472

Operating expense (excluding depreciation)
 
111,261

 
4,524

 
25,115

 

 

 
140,900

Lease operating expense
 

 

 

 

 
5,673

 
5,673

Depreciation, depletion and amortization
 
6,008

 
1,881

 
2,353

 
2,018

 
2,637

 
14,897

Loss (gain) on sale of assets, net
 

 

 

 

 
624

 
624

General and administrative expense
 

 

 

 

 
34,304

 
34,304

Acquisition and integration expense
 

 

 

 

 
11,687

 
11,687

Operating income (loss)
 
$
(33,419
)
 
$
24,142

 
$
17,055

 
$
3,631

 
$
(48,941
)
 
$
(37,532
)
________________________________________________________
(1)
Our logistics operations consist primarily of intercompany transactions which eliminate on a consolidated basis.
(2)
Includes eliminations of intersegment Revenues and Cost of revenues (excluding depreciation) of $271.9 million, $330.0 million and $205.9 million for the years ended December 31, 2016, 2015 and 2014, respectively.

46




Below is a summary of key operating statistics for the refining segment for the years ended December 31, 2016, 2015 and 2014:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Total Refining Segment
 
 
 
 
 
 
Feedstocks Throughput (Mbpd) (1)
 
86.0

 
77.3

 
68.2

Refined product sales volume (Mbpd) (1)
 
90.6

 
76.8

 
69.1

 
 
 
 
 
 
 
Hawaii Refinery
 
 
 
 
 
 
Feedstocks Throughput (Mbpd)
 
70.2

 
77.3

 
68.2

Source of Crude Oil:
 
 
 
 
 
 
North America
 
41.7
%
 
47.7
%
 
48.8
%
Latin America
 
3.9
%
 
8.0
%
 
23.4
%
Africa
 
13.7
%
 
8.3
%
 
3.7
%
Asia
 
30.0
%
 
33.0
%
 
1.3
%
Middle East
 
10.7
%
 
2.1
%
 
22.8
%
Europe
 
%
 
0.9
%
 
%
Total
 
100.0
%
 
100.0
%
 
100.0
%
 
 
 
 
 
 
 
Yield (% of total throughput)
 
 
 
 
 
 
Gasoline and gasoline blendstocks
 
26.8
%
 
26.2
%
 
24.5
%
Distillate
 
44.7
%
 
44.1
%
 
38.9
%
Fuel oils
 
20.1
%
 
22.0
%
 
30.7
%
Other products
 
4.8
%
 
4.7
%
 
2.9
%
Total yield
 
96.4
%
 
97.0
%
 
97.0
%
 
 
 
 
 
 
 
Refined product sales volume (Mbpd)
 
 
 
 
 
 
On-island sales volume
 
61.7

 
62.4

 
53.9

Exports sale volume
 
12.5

 
14.4

 
15.2

Total refined product sales volume
 
74.2

 
76.8

 
69.1