Item  1. BUSINESS

 

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. 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.

2) Retail - Our retail outlets sell gasoline, diesel and retail merchandise throughout the island of Oahu as well as the neighboring islands of Maui, Hawaii and Kauai. Our retail network includes Tesoro and "76" branded retail sites, company-operated convenience stores, sites operated in cooperation with 7-Eleven and other sites operated by third parties.

3) Logistics - We own and operate terminals, pipelines, a single-point mooring 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 also 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 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.

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 refining, retail and logistics segments effective April 1, 2015. Mid Pac distributes gasoline and diesel through over 80 locations across the State of Hawaii and owns four terminals. In conjunction with the acquisition, we also obtained the exclusive rights to the "76" brand in Hawaii through 2024.

In addition to the three operating segments described above, we have two additional reportable segments: (i) Texadian (formerly the "Commodity Marketing and Logistics segment") 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.

Recent developments

On December 17, 2015 , we entered into a credit agreement (the "KeyBank Credit Agreement") in the form of a revolving credit facility up to $5 million (" KeyBank Revolving Credit Facility "), which provides for revolving loans and for the issuance of letters of credit and a term loan agreement (“ KeyBank Term Loans ”), which provided term loans totaling $110 million . As of December 31, 2015 , we had not made any borrowings under the KeyBank Revolving Credit Facility .

During 2015, we changed our reportable segments to separate our retail and logistics operations from our refining operations due to a change in senior leadership, organizational structure, the acquisition of Mid Pac and to reflect how we currently make financial decisions and allocate resources. We have five reportable segments: (i) Refining , (ii) Retail , (iii) Logistics , (iv) Texadian and (v) Corporate and Other. We previously reported results for the following three business segments: (i) Refining, Distribution and Marketing, (ii) Natural Gas and Oil Production, and (iii) Commodity Marketing and Logistics. Additionally, beginning in 2015 we have included all general and administrative costs in our Corporate and Other segment because we manage those costs on a consolidated basis. We have recast the segment information for the years ended December 31, 2014 and 2013 to conform to the current period presentation. Please read  Note 19—Segment Information  to our consolidated financial statements included in this Annual Report on 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,” “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 .

HAWAII OPERATIONS

Refining

Our 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 from North America, South America, Southeast Asia, the Middle East, Russia and other sources. The 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 refinery uniquely meets the demands of the Hawaii market.

Crude oil is transported to Hawaii in tankers, which discharge through our single-point mooring. Our three underwater pipelines from the single-point mooring allow crude oil and refined products to be transferred to and from the refinery.

Crude oil is received into the refinery tank farm, which consists of 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 refinery’s 2.5 million barrels of product tankage.    The refinery storage capacity allows us to manage the various product requirements of the State of Hawaii.

We have a Supply and Offtake Agreement with J. Aron & Company ("J. Aron") that allows us to finance our hydrocarbon inventories. Under the Supply and Offtake Agreement, J. Aron holds title to all crude oil and refined product stored in tankage at the 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.

Set forth below is a summary of the capacity of our refinery:

The refinery operated at an average throughput of 77 thousand barrels per day, or 82% utilization, for the year ended December 31, 2015 . Below is a summary of our throughput percentage by type of crude oil and the product yield percentage for the years ended December 31, 2015 , 2014 and 2013 :

Our refining business sells refined products through our logistics network to wholesale and bulk customers and to our retail business. 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 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 operations. During the course of 2015 , 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 $6.88 per barrel during 2015 with a low of $5.44 per barrel in the fourth quarter and a high of $8.24 per barrel in the second quarter. The Mid Pacific 4-1-2-1 crack spread averaged $8.31 per barrel during 2015 with a low of $6.50 per barrel in the fourth quarter and a high of $9.76 per barrel in the second quarter.

Below is a summary of average crack spreads for the years ended December 31, 2015 , 2014 and 2013 :

⁽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 good 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. Our overall crack spreads benefited from the pricing lag effect as the crude oil market experienced a decline in prices throughout the year. During the fourth quarter of 2015, we began economically hedging the pricing lag effect.

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 staffs 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 refinery, through our facility with J. Aron, has access to a large variety of markets for crude oil imports and product exports. Please read “ Item 7. — Management's Discussion and Analysis of Financial Condition and Results of Operations — Commitments and Contingencies — Supply and Offtake Agreements ”.

Our refined product sales, outside the Hawaii market, typically target the Eastern Asia and U.S. West Coast markets.

Retail

The retail segment includes 91 locations where the Company sets the price to the retail consumer. Of these 91 locations, 39 are outlets operated by our personnel and include various sizes of kiosks, snack shops or convenience stores. The remaining 52 locations are unmanned cardlocks stations or sites operated by third parties where we retain ownership of the fuel and set retail pricing.

The Company holds exclusive licenses within the state of Hawaii to utilize both the Tesoro and the “76” brands for retail locations. All of the manned locations (and one cardlock) are currently operated under one of those brands (see chart below). The initial term of the Tesoro license expires in September 2017 and we have two one-year extension options. 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:

Competition

Competitive factors that affect our retail performance include product price, station appearance, location and brand awareness and our competitors include an increasing number of national retailers. 

Logistics

Our logistics network extends throughout the state of Hawaii. On Oahu, the system begins with our single-point mooring (“SPM”) located 1.7 miles offshore of our refinery. This SPM allows for the safe, reliable and efficient receipt of crude shipments to the refinery, as well as both the receipt and export of finished products. Connecting the SPM to the refinery are three undersea pipelines: a 30-inch line for crude oil and a 20-inch line and a 16-inch line, both for the import or export of refined products. From the 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.

The Oahu logistics network also includes a 27-mile wholly-owned and operated pipeline network that transports refined products from our 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 refinery to Kalaeloa Barbers Point Harbor, approximately three miles from the 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 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 30,000 barrels, as well as contractual rights to utilize strategically located third-party facilities both near the 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 86,000 barrels of capacity and the Ne’ena with 50,000 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.

The barges deliver to and product is dispensed from a neighbor island network of seven petroleum terminals, with the approximate locations depicted below:

    

Competition

Currently, substantially all of our revenues from our logistics segment represent intercompany transactions that are eliminated in consolidation.

Hawaii Market

The Hawaii economy continues to grow. The Hawaii State Department of Business, Economic Development and Tourism (“DBEDT”) reported a population increase of 3% from 2013 to 2015. Real personal income growth is projected by DEBDT to be 3% for 2016. The number of visitors arriving by air also increased. During 2015 , visitor arrivals increased 4.1% and continued growth is forecasted.

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.

OTHER OPERATIONS

Laramie Energy

We currently 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 Energy II") in conjunction with our corporate reorganization in August 2012 and cash contributions made in 2015.

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 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% . Laramie Energy 's assets are located in Garfield, Mesa and Rio Blanco Counties, Colorado. These properties

produce primarily from the Mesaverde Formation and, to a lesser extent, the Mancos Formation. The majority of the acreage that will be acquired is adjacent to Laramie Energy's existing assets.

As of December 31, 2015 , the estimated proved reserves of Laramie Energy and the estimated proved reserves we own indirectly through Laramie Energy are the following: 

For more information regarding our proved undeveloped reserves, please read "Item 2 — Properties — Reserves — Proved Undeveloped Reserves".

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, 2015 (unaudited, in thousands): 

________________________________________________

Reconciliation of PV-10 to Standardized Measure

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 PV-10 to the standardized measure of discounted future net cash flows at December 31, 2015 (in thousands): 

For more information on our natural gas and oil operations, please read “ Item 2. — Properties .” 

Other non-operated oil and gas interests

We also own other non-operated positions in producing and non-producing natural gas and oil interests, undeveloped leasehold interests and related assets in Colorado and New Mexico and interests in a producing federal unit offshore California. As of December 31, 2015, our estimated proved reserves related to other non-operated natural gas and oil interests of 224 MMcfe represented less than 1% of our total proved reserves owned directly and indirectly through Laramie Energy of 161,065 MMcfe. Please read Note 22—Supplemental Oil and Gas Disclosures (Unaudited) to our consolidated financial statements 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.

Competition

The principal markets for natural gas and oil are refineries and transmission companies that have facilities near our producing properties. Natural gas and oil produced from our wells is 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, we are 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.

The natural gas and oil business is highly competitive in the acquisition of natural gas and oil leases, exploration and production capabilities and equipment and personnel required to find and produce reserves. Our competitors may be able to pay more for desirable leases than our financial or personnel resources permit. Because we are a non-operator, our competitors are in a much stronger position than we are to evaluate, bid for and purchase properties and to explore for and produce natural gas and 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.

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, 2015 and 2014.

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.

As of December 31, 2015 , a total of twelve claims totaling approximately $23.1 million remain to be resolved by the Recovery Trustee. We have agreed to settle six of these claims for aggregate consideration of approximately $666 thousand , subject to final documentation and payment, and have filed or will file notices of objection with respect to liability for the other claims.   

The largest remaining proof of claim 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. 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, owned an approximate 2.4% 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. At December 31, 2015 , we have reserved approximately $1.1 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at period end. Please read “Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commitments and Contingencies – Bankruptcy Matters”.

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, 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 carbon dioxide, methane, nitrous oxide and other gases commonly known as greenhouse gases (“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” and 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 Clean Air Act 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.

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 carbon dioxide 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.

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.

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 CO ₂ 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 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 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 CO ₂ 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. 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 NO _X and SO ₂ 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 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 refinery is located, has met even the most recent NAAQS and the 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 SO ₂ levels are already elevated due to volcanic activity, are switching from LSFO to diesel fuel and 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 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 refinery because a portion of its production capacity and product mix has historically been dedicated to supplying the 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 new 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 refinery can be tuned, operated and modified to respond to a shift in customer fuel specifications and additional demand for distillates, an on-going 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 or in the alternative 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, gives 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. In September 2015, our refinery was granted small volume refinery status by the EPA. Along with credit and trading options, potential capital upgrades for the refinery are being evaluated.

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 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 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 refinery is capable of producing the 1% sulfur residual fuel oil that was previously required within the ECA. Although our 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 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 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 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 $350 million and for offshore facilities of all removal costs plus $33.65 million and lesser limits for some vessels depending upon their size. The U.S. Coast Guard has proposed to increase the onshore liability to $404.6 million based on an inflation adjustment. 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, oil 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 has generated substantial public comment and the EPA’s Science Advisory Board has scheduled public meetings and teleconferences through at least March 2016 to receive comment on the study. The study’s findings are intended to improve scientific understanding to guide the EPA’s regulatory oversight, guidance and, where appropriate, rulemaking related to hydraulic fracturing. 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 Colorado and some other 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 has also been introduced in Colorado that, if successful, would amend the state constitution to give local governments control over oil and natural gas drilling in their areas. Depending on the results of the EPA study and other developments related to hydraulic fracturing, 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 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.

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 August 2015, the EPA proposed rules to address methane emissions of new oil and gas wells and in January 2016, the BLM proposed 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

Tesoro is currently negotiating a consent decree with the EPA and the United States Department of Justice ("DOJ") concerning alleged violations of the federal Clean Air Act related to the ownership and operation of multiple facilities owned or formerly owned by Tesoro and its affiliates (“Consent Decree”), including our refinery. It is anticipated that the Consent Decree will be finalized sometime during 2016 and will require certain capital improvements to our refinery to reduce emissions of air pollutants. 

We estimate the cost of compliance with the final decree could be $20 million to $30 million . However, Tesoro is responsible under the Environmental Agreement for reimbursing us for all reasonable third-party capital expenditures incurred for the construction, installation and commissioning of such capital projects and for the payment of any fines or penalties imposed on us arising from the Consent Decree to the extent related to acts or omission of Tesoro or us prior to the Closing Date. Tesoro’s obligation to reimburse us for such fines and penalties is not subject to a monetary limitation; however, the obligation relating to fines and penalties terminates on the third anniversary of the Closing Date.

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. The impact of the ongoing economic downturn on natural gas supply and demand fundamentals has 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 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 newly formed 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 as the functions of the former BOEMRE are fully divested and implemented in the two federal bureaus. At this time, we cannot predict the impact that this reorganization, or future regulations of enforcement actions taken by the new agencies, may have on our operations. 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 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: 

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. 

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 in periods of rising commodity prices, 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, 2015, no single customer accounted for 10% or more of our revenues. No single customer accounted for 10% or more of our total trade accounts receivable as of December 31, 2015.

EMPLOYEES

At December 31, 2015 , we employed 744 people, 147 of which are nonexempt employees at the refinery who are represented by the United Steelworkers Union ("USW"). Our previous collective bargaining agreement 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 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 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 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 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. 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.