Par Pacific 8K Other Events | PARR 22 May 15

Exhibit 99.1

Item 1. BUSINESS

General

We are a diversified energy company based in Houston, Texas. 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.

Our refining and distribution segment consists of a refinery in Kapolei, Hawaii, refined products terminals, pipelines, a single-point mooring and trucking operations which produce refined products and distribute gasoline and diesel throughout Hawaii. The refinery produces ultra-low sulfur diesel, gasoline, jet fuel, marine fuel, and other associated refined products primarily for consumption in Hawaii. Our wholesale distribution efforts focus on jobbers and other non-end users.

Our retail segment consists of 31 Tesoro branded retail sites, one cardlock facility, five sites operated by third parties and 25 company operated convenience stores.

The refining and distribution segment and the retail segment were established through the acquisition of Hawaii Independent Energy, LLC ("HIE"; formerly known as Tesoro Hawaii, 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 HIE, terminated a transition services agreement with Tesoro, and greatly reduced our reliance on third-party service providers in operating our business.

Our natural gas and oil production segment consists of natural gas and oil assets that are non-operated and are concentrated in our 33.34% ownership of Piceance Energy, LLC ("Piceance Energy"), a joint venture entity operated by Laramie Energy II, LLC ("Laramie") and focused on producing natural gas in Garfield and Mesa Counties, Colorado. Piceance Energy was formed as part of our reorganization and resulted from the contribution of properties located in the Piceance Basin in Colorado by us and by Laramie. In addition, we own non-operated interests in Colorado and offshore California and overriding royalty interests in New Mexico. Our interests are heavily weighted towards natural gas and natural gas liquids.

Our commodity marketing and logistics segment focuses on sourcing, marketing, transporting, and distributing crude oil and refined products. Our logistics capability consists of historical pipeline shipping status, a railcar fleet, and expertise in contracted chartering of tows and barges, with the capability of moving crude oil from land-locked locations in the Western U.S. and Canada to the refining hubs in the Midwest, Gulf Coast, and East Coast regions of the U.S.

We amended our certificate of incorporation to implement a one-for-ten (1:10) reverse stock split of our issued and outstanding common stock, par value $0.01 per share, effective on January 29, 2014 for trading purposes. All references in the financial statements to the number of shares of common stock or warrants, price per share, and weighted average number of common stock shares outstanding prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis, unless otherwise noted.

As a result of the HIE acquisition, our results of operations for any period after September 30, 2013 will not be comparable to any period prior to that date. We anticipate our results of operations, capital and liquidity position, and the overall success of our business will depend, in large part, on the results of our refining and distribution segment. The differences, or spread, between the crude oil prices we pay and the prices we receive for finished products (known as the “crack spread”), both of which are largely beyond our control, will be the primary driver of the refining and distribution segment results of operations and, therefore, of our profitability.

On June 2, 2014, we entered into an agreement and plan of merger with Koko’oha. Koko’oha owns 100% of the outstanding membership interests of Mid Pac Petroleum, LLC (“Mid Pac”), a Delaware limited liability company.

Mid Pac distributes gasoline and diesel through over 80 locations across the State of Hawaii, owns four terminals and has throughput rights to a fifth. Mid Pac has the exclusive rights to the "76" brand in Hawaii through 2024. During the year ended December 31, 2014, Mid Pac sold 74 million gallons of fuel (4,827 bpd) of which 58 million gallons were gasoline (3,783 bpd). On January 1, 2015, we began supplying Mid Pac with gasoline and diesel under a supply agreement with a one year term and

Exhibit 99.1

two one year extensions. Mid Pac's added gasoline volume is expected to increase our on-island gasoline sales and decrease our requirement to export gasoline range materials. Historically, we estimated that each exported barrel of refined product costs us between $6 and $10 per barrel (including shipping costs, lost product value and other costs). Mid Pac also offers us access to the Kauai marketplace through Mid Pac’s Kauai terminal and network of three retail and eight cardlock sites. In addition, Mid Pac is the fee owner of 22 of its retail sites, its current office space in downtown Honolulu and three unimproved land parcels on Kauai.

Pursuant to the Mid Pac acquisition, we expect to acquire 100% of Koko’oha and Mid Pac for $107 million, less estimated long-term liabilities, plus estimated merchandise and product inventory, subject to other adjustments as set forth in the agreement and plan of merger. We believe we have satisfied the Federal Trade Commission's concerns under the Hart-Scott-Rodino Act and anticipate entering into a consent order in mid-March. We expect to close the acquisition in April of 2015.

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 Report, the terms “Par,” “we,” “our,” and “us” refer to Par Petroleum Corporation and its consolidated subsidiaries unless the context suggests otherwise.

Refining and Distribution

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, hydrotreating, and naphtha reforming units, which produce ultra-low sulfur diesel, gasoline, jet fuel, marine fuel, and other associated refined products. We believe the configuration of our refinery uniquely meets the demands of the Hawaii economy and, through our logistics network, provides critical energy infrastructure to the State of Hawaii.

Crude oil is transported to Hawaii in tankers, which discharge through our single-point mooring, approximately two miles offshore from the refinery. 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 storage. Following crude receipt, we process the crude through the conversion units into refined products and store the material within the refinery’s 2.5 million barrels of refined product tankage. The refinery storage capacity allows us to manage the various product requirements of the State of Hawaii. From the refinery gate, we distribute refined products through our logistics network throughout the Island of Oahu as well the neighboring islands of Maui, Hawaii and Kauai.

Our logistics network on Oahu consists of a 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 our leased and operated Sand Island terminal, Honolulu International Airport, interconnections to Navy and Air Force fuel facilities, and 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, interconnect 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. 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 on Maui, Hawaii and Kauai. We also have access through neighboring island terminals to pipelines interconnecting the respective harbors to the respective storage facilities. We operate proprietary trucking operations across the neighboring islands and supplement any requirements in excess of our capabilities with third-party providers.

In addition to intercompany sales to our retail segment, we distribute our products through two main channels: wholesale and bulk. Our wholesale distribution efforts focus on jobbers and other non-end users. Bulk distribution primarily serves utilities, airports, military bases, marine vessels and industrial end-users, and exports.

We have in place a Supply and Exchange Agreement with Barclays Bank, PLC ("Barclays") that allows us to finance our hydrocarbon inventories. Under the Supply and Exchange Agreement, Barclays holds title to all crude oil and refined product stored in tankage at the refinery. We purchase crude oil from Barclays on a daily basis at market prices and deposit refined products into the exchange. The exchange arrangement allows us to sell refined products to customers on a daily basis and replace these sales with daily production. Barclays holds title to all refined products within the exchange.

Exhibit 99.1

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



Refining Unit		Capacity (MBPD)
Crude Unit		94
Vacuum Distillation Unit		40
Hydrocracker		18
Catalytic Reformer		13
Visbreaker		11
Hydrogen Plant (MMCFD)		18
Naphtha Hydrotreater		13
Co-generation Turbine Unit (MW)		20

Over the course of 2014, we increased the amount of North American crude used to supply the refinery, particularly Alaska North Slope (ANS) crude. The refinery operated at an average throughput of 69 thousand barrels per day, or 73% utilization, for the year ended December 31, 2014. Below is a summary of our throughput percentage by type of crude oil and the product yield percentage by quarter for the year ended December 31, 2014:



	Total 2014		Q4		Q3		Q2		Q1
Throughput
Heavy Crude ⁽¹⁾	23	%	22	%	18	%	25	%	29	%
Light Crude	77	%	78	%	82	%	75	%	71	%
Total Throughput	100	%	100	%	100	%	100	%	100	%

Yield
Gasoline and gasoline blendstocks	25	%	24	%	25	%	26	%	24	%
Jet fuel	25	%	25	%	26	%	24	%	26	%
Diesel fuel	13	%	13	%	15	%	12	%	12	%
Heavy fuel oils, residual products, internally produced fuel, and other	38	%	39	%	34	%	38	%	40	%
Total Yield	101	%	101	%	100	%	100	%	102	%

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⁽¹⁾We define heavy crude oil as crude oil with an American Petroleum Institute gravity of 24 degrees or less.

The following map depicts the location of our terminal assets throughout Hawaii:

Exhibit 99.1

Market Discussion

The profitability of our Hawaii business is heavily influenced by crack spreads in both the Singapore and 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 crack spread (or four barrels of Brent converted into one barrel of gasoline, two barrels of distillate (gasoil and jet fuel), and one barrel of fuel oil) best reflects a market indicator for our operations. However, there is a portion of our sales that reference the West Coast market. During the course of 2014, both markets exhibited significant volatility with lows reached during the late second and early third quarter and significant improvement during the fourth quarter. The Singapore 4-1-2-1 crack spread averaged $6.22 / bbl during 2014 with a low of $4.79 / bbl in the second quarter and a high of $7.39 / bbl in the fourth quarter.

During a rapidly declining crude market, we tend to benefit from expanding crack spreads as changes in refined product prices tend to lag crude prices. The majority 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 price setting mechanism. During the fourth quarter we benefited from these prior week or prior month average pricing mechanisms in our contracts as crude and product prices declined.

Hawaii Economy

The Hawaii economy has grown consistently since 2012. According to the Hawaii State Department of Business, Economic Development and Tourism ("DBEDT"), Hawaii' s population increased 2% from 2012 to 2014. Real personal income growth was projected by DBEDT to be 2.6% for 2014. This is the highest real personal income growth since 2006. Also on the rise are registered, taxable gasoline vehicles. According to DBEDT, passenger and freight vehicles increased 3.7% and 2% during 2014, respectively. Total registered, taxable gasoline vehicles increased 20% from 2010 to 2014. In addition, DBEDT estimated visitors arriving by air increased 1.4% during 2014 with continued growth forecasted into the future.

Seasonality

Demand for gasoline is somewhat higher in Hawaii during the summer months than during the winter months due to seasonal increases in highway traffic and construction work. Decreased demand during the winter months can lower gasoline prices. Partially offsetting this decrease, demand for jet fuel increases in the winter months as tourism increases. Refining margins remain volatile and our results of operations may not reflect these historical seasonal trends.

Retail

Our retail distribution network includes 31 Tesoro branded retail sites, one cardlock facility, five sites operated by third parties and 25 company operated convenience stores that sell gasoline, diesel and other retail merchandise. Our retail operations purchase gasoline and diesel from our refining and distribution segment. We have a Trademark License Agreement with Tesoro granting us the right to use certain trademarks, color marks, and miscellaneous designs at our retail sites. The initial term of the agreement expires in September 2017 and we have two one-year extension options.

Natural Gas and Oil

All of the assets contributed to Piceance Energy by Par and Laramie are located in Garfield and Mesa Counties, Colorado. All contributed properties produce primarily from the Mesaverde Formation and, to a lesser extent, the Mancos Formation, and some of the contributed acreage is contiguous. 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. Our natural gas and oil operations primarily consist of activities related to our minority interest in Piceance Energy.

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.

As of December 31, 2014, the estimated proved reserves of Piceance Energy are the following (unaudited):



	Natural Gas (MMcf)	Oil (MBbls)	NGLs (MBbls)	Total (MMcfe) ⁽¹⁾
Proved Developed	146,537	585	3,675	172,103
Proved Undeveloped	488,587	1,600	14,548	585,475
Total Proved	635,124	2,185	18,223	757,578

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⁽¹⁾	MMcfe is computed using a ratio of 6 Mcf to 1 barrel of oil or NGL.

Exhibit 99.1

The following table presents the estimated proved reserves that we own directly and indirectly through Piceance Energy as of December 31, 2014 (unaudited):



	Natural Gas (MMcf)	Oil (MBbls)	NGLs (MBbls)	Total (MMcfe) ⁽¹⁾
Company:
Proved Developed	601	77	17	1,165
Proved Undeveloped	—	—	—	—
Total Proved Reserves - Company	601	77	17	1,165
Company Share of Piceance Energy:
Proved Developed	48,855	195	1,226	57,381
Proved Undeveloped	162,895	533	4,850	195,193
Total Proved Reserves - Piceance Energy	211,750	728	6,076	252,574
Total Combined Proved Reserves	212,351	805	6,093	253,739

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⁽¹⁾	MMcfe is computed using a ratio of 6 Mcf to 1 barrel of oil or NGL.

For more information regarding our proved undeveloped reserves, see 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 directly and indirectly through Piceance Energy as of December 31, 2014 (unaudited):



	Proved Developed Producing		Proved Developed Non-producing		Proved Undeveloped		Total ⁽¹⁾
	(M$)		(M$)		(M$)		(M$)
Company:
Estimated pre-tax future net cash flows	$	2,655	$	—	$	—	$	2,655
Standardized measure of discounted future net cash flows	$	1,766	$	—	$	—	$	1,766
Company Share of Piceance Energy:
Estimated pre-tax future net cash flows	$	108,557	$	34,892	$	349,432	$	492,881
Standardized measure of discounted future net cash flows	$	63,105	$	14,194	$	93,300	$	170,599
Total:
Estimated pre-tax future net cash flows	$	111,212	$	34,892	$	349,432	$	495,536
Standardized measure of discounted future net cash flows	$	64,871	$	14,194	$	93,300	$	172,365

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⁽¹⁾

Prices are based on the historical first 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 $84.93 per barrel of oil, $35.74 per barrel of natural gas liquids, and $4.68 per Mcf of natural gas.

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. 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.

Exhibit 99.1

The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2014 (in thousands):



	Company		Company Share of Piceance Energy		Total
PV-10	$	1,766	$	170,599	$	172,365
Present value of future income taxes discounted at 10% ⁽¹⁾	—		—		—
Standardized measure of discounted future net cash flows	$	1,766	$	170,599	$	172,365

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⁽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 16—Income Taxes for further information.

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

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. 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 oil, which is deducted from or accounted for in the price paid for the oil.

Commodity Marketing and Logistics

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 river barges and pipelines. We also lease a fleet of approximately 150 railcars. We purchase and resell crude oil primarily from the Western United States and Canada to customers in the Midwest, Gulf Coast, and East Coast regions of the U.S. and deliver the crude oil via rail, pipeline, and barge. We also have historical pipeline positions on lines moving Canadian crude oil south.

We sell crude oil primarily to end users (refiners and their suppliers) and other market participants and may also purchase, sell, or exchange crude oil with other market participants to optimize logistics.

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.

The refining and distribution segment 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 Barclay’s (please read “Item 7. — Management's Discussion and Analysis of Financial Condition and Results of Operations - Commitments and Contingencies – Supply and Exchange Agreements”), has access to a large variety of markets for crude oil imports and product exports.

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

The natural gas and oil production segment 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.

The commodity marketing and logistics segment is a capital-intensive, 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 global supply and demand.

Exhibit 99.1

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 United States 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 and Laramie, Piceance 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 Piceance 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 Chief Legal Officer 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 has released approximately $5.2 million to us, which is 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 year ended December 31, 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.

As of December 31, 2014, a total of 27 claims totaling approximately $26.5 million remain to be resolved by the Recovery Trustee. 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 a 2.41934% 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, 2014, 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,

Exhibit 99.1

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 United States 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.

Exhibit 99.1

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 below reduced below 2010 levels and are projected to be less than the 1990 levels by 2020, the refinery should be able to demonstrate that no further reductions are required to meet the statewide goal and accordingly 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. 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 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 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 SO₂levels 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 December 17, 2014, the EPA proposed rules that would substantially tighten the NAAQS for ground-level ozone. If adopted, the 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.

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 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 United States 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

Exhibit 99.1

scale for use in traditional gasoline engines. Since April 2006, the State of Hawaii has required that a minimum of 9.2% ethanol be blended into at least 85% of the gasoline pool, but the regulation also limited the amount of ethanol to no more than 10%. Consequently, unless either the state or 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. Along with credit and trading options, potential capital upgrades for the refinery are being evaluated. The American Petroleum Institute and American Fuel and Petrochemical Association may challenge the final regulation. On December 30, 2014, HIE filed an application with the EPA to qualify as a Small Volume Refinery, which if approved, would extend the compliance deadline three years until January 31, 2020 and provide more opportunities to create, acquire and use sulfur credits as a means of demonstrating compliance with Tier 3. Recognition and approval as a Small Volume Refinery under Tier 3 would not constrain rates nor be invalidated by future throughput rates that exceed the threshold criteria of 75,000 bpd on an annual aggregate basis.

Beginning on June 30, 2014, new sulfur standards for fuel oil used by marine vessels operating within 200 miles of the US 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 US 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

In both our refining and our exploration and production businesses, we 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 other 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

Exhibit 99.1

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 United States 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 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 United States, 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 United States 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.

Exhibit 99.1

Hydraulic Fracturing

Our 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. The EPA published a progress report on this study in December 2012, but has delayed release of its final draft report previously expected in 2014. Additionally, the United States Bureau of Land Management (”BLM”) proposed to regulate the use of hydraulic fracturing on federal and tribal lands, but following extensive public comment on the proposals, BLM issued a revised draft proposal. The revised proposal addresses disclosure of fluids used in the fracturing process, integrity of well construction, and the management and disposal of wastewater that flows back from the drilling process. 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 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 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 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. While these new requirements increased the cost of natural gas production, we were not 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 United States. 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”), Hawaii Pacific Energy (a wholly-owned subsidiary of Par created for purposes of acquiring HIE), Tesoro, and HIE entered into an Environmental Agreement (“Environmental Agreement”), which allocated responsibility for known and contingent environmental liabilities related to the acquisition of HIE as follows:

Exhibit 99.1

•

Consent Decree. Tesoro is currently negotiating a consent decree with the EPA and the United States Department of Justice 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 first half of 2015 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 $25 million. However, Tesoro is responsible under the Environmental Agreement for reimbursing HIE 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 HIE arising from the Consent Decree to the extent related to acts or omission of Tesoro or HIE prior to the Closing Date. Tesoro’s obligation to reimburse HIE 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.


•	UST Tank Replacements. Tesoro replaced, at its expense, the underground storage tanks ("UST") at six retail locations. The tank replacements were completed at five of the stations during 2014. The sixth location was completed during the first quarter of 2015.

•

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 HIE 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 HIE 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.

Exhibit 99.1

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

Exhibit 99.1

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 United States. 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 United States 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

Exhibit 99.1

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.

Employees

At December 31, 2014, we employed 577 people, 132 of which are nonexempt employees at the refinery who are represented by the United Steelworkers Union ("USW"). Our current collective bargaining agreement expired in January 2015 and we are continuing negotiations with the USW on a new collective bargaining agreement. During this period, employees

Exhibit 99.1

represented by the USW have continued to work under the existing agreement pursuant to a 24-hour rolling extension. We consider our relations with our represented and non-represented employees to be satisfactory.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this 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 of Par and our subsidiaries 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 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 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” of our Annual Report on Form 10-K or in “Item 7. — Management's Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this 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.

Exhibit 99.1

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

We are a diversified energy company based in Houston, Texas, created through the successful reorganization of Delta Petroleum Corporation in August 2012. The reorganization converted unsecured debt to equity and allowed us to preserve significant tax attributes. We currently operate in four segments:


•	refining and distribution;


•	retail;


•	natural gas and oil production; and


•	commodity marketing and logistics.

Our refining and distribution segment consists of a refinery in Kapolei, Hawaii, refined products terminals, pipelines, a single-point mooring and trucking operations. Our retail segment consists of retail outlets which distribute gasoline, diesel and retail merchandise throughout Hawaii. Our natural gas and oil assets are non-operated and are concentrated in our 33.34% ownership of Piceance Energy, a joint venture focused on producing natural gas in Garfield and Mesa Counties, Colorado. Our commodity marketing and logistics segment focuses on sourcing, transporting, marketing and distributing crude oil from Canada and the Western U.S. to refining hubs in the Midwest, Gulf Coast, and East Coast regions of the U.S.

On September 25, 2013, we acquired HIE from Tesoro. As a result, our results of operations for any period after September 30, 2013 will not be comparable to any period before September 30, 2013. While we will continue to recognize our proportionate share of the earnings or losses of Piceance Energy and reflect the results of operations of our commodity marketing and logistics segment, we anticipate our results of operations, capital and liquidity positions, and the overall success of our business will depend, in large part, on the results of our refinery operations. The crack spread will be the primary driver of the refining and distribution segment’s results of operations and, therefore, of our profitability.

We amended our certificate of incorporation to implement a one-for-ten (1:10) reverse stock split of our issued and outstanding common stock, par value $0.01 per share, effective on January 29, 2014 for trading purposes. All references to the number of shares of common stock or warrants, price per share, and weighted average number of common stock shares outstanding prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis, unless otherwise noted.

Agreement and Plan of Merger

On June 2, 2014, we entered into an agreement and plan of merger with Koko’oha to indirectly acquire 100% of the outstanding membership interests of Mid Pac. Mid Pac owns and operates several terminals and retail gasoline stations. Pursuant to the merger agreement, we expect to acquire 100% of Koko’oha and Mid Pac for $107 million, less estimated long-term liabilities, plus estimated merchandise and product inventory, subject to other adjustments as set forth in the merger agreement. We believe we have satisfied the Federal Trade Commission's concerns under the Hart-Scott-Rodino Act and anticipate entering into a consent order in mid-March. We expect to close the acquisition in April of 2015.

Results of Operations

Factors Impacting 2014 Results

The year ended December 31, 2014 was a transition year for us as we implemented systems and processes necessary to support our acquisition of HIE. Substantial improvements were achieved across the company including crude sourcing and on-island sales growth. Additionally, we experienced improvements in our accounting and information systems through the early termination of the transition services agreement with Tesoro. We believe these are the building blocks for future profitability and additional acquisitions.

Over the course of the year we observed significant volatility in both the crude and refined products markets. The extremes of the second quarter and fourth quarter were most notable as crude markets swung from relatively tight to significantly over-supplied in a short period of time. During the fourth quarter, we observed compression in crude differentials and a shift in the price structure of the Brent crude market to contango compared to the prior quarters. These factors reduced our feedstock costs in the quarter. Crack spreads also expanded during the fourth quarter relative to the lows of the second quarter. The decline in crude prices during the fourth quarter allowed us to benefit from sales contracts to customers that price on prior week or prior month averages.

Exhibit 99.1

In the fourth quarter, we also experienced our highest level of on-island sales with the commencement of a military jet contract. We expect further increases to on-island sales commencing in 2015 as a result of the Mid Pac volumes and other commercial opportunities. Our acquisition and integration costs remain elevated due to the ongoing expenditures associated with seeking regulatory approvals for the pending Mid Pac acquisition.

The following table summarizes our results of operations for the years ended December 31, 2014 and 2013. The following should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Report.



	Year Ended December 31,
	2014			2013			Increase (Decrease)			% Change⁽¹⁾
Gross Margin
Refining and distribution	$	114,397		$	(4,909	)	$	119,306		(2,430	)%
Retail	44,523			9,452			35,071			371	%
Commodity marketing and logistics	5,649			16,666			(11,017		)	(66	)%
Natural gas and oil	5,984			7,739			(1,755		)	(23	)%
Total gross margin	170,553			28,948
Operating expense, excluding depreciation, depletion, and amortization expense	146,573			32,927			113,646			345	%
Depreciation, depletion, and amortization	14,897			5,982			8,915			149	%
Loss (gain) on sale of assets, net	624			(50		)	674			(1,348	)%
Trust litigation and settlements	—			6,206			(6,206		)	(100	)%
General and administrative expense	34,304			21,494			12,810			60	%
Acquisition and integration costs	11,687			9,794			1,893			19	%
Total operating expenses	208,085			76,353
Operating loss	(37,532		)	(47,405		)
Other income (expense)
Interest expense and financing costs, net	(19,783		)	(19,426		)	(357		)	2	%
Other income (expense), net	(312		)	758			(1,070		)	(141	)%
Change in value of common stock warrants	4,433			(10,159		)	14,592			(144	)%
Change in value of contingent consideration	2,849			—			2,849			NM
Equity earnings (losses) from Piceance Energy LLC	2,849			(2,941		)	5,790			(197	)%
Total other expense, net	(9,964		)	(31,768		)
Loss before income taxes	(47,496		)	(79,173		)
Income tax benefit	455			—			455			NM
Net loss	$	(47,041	)	$	(79,173	)

⁽¹⁾NM - Not Meaningful

Non-GAAP Performance Measure

Management uses gross margin to evaluate our operating performance. Gross margin is considered a non-GAAP financial measure. This measure should not be considered a substitute for, or superior to, measures of financial performance prepared in accordance with U.S. GAAP, and our calculations thereof may not be comparable to similarly entitled measures reported by other companies.

Gross Margin

Gross margin is defined as revenues less cost of revenues. We believe gross margin is an important measure of operating performance and provides useful information to investors because it eliminates the impact of volatile market prices on revenues and demonstrates the earnings potential of the business before other fixed and variable costs. In order to assess our operating performance, we compare our gross margin to industry gross margin benchmarks.

Exhibit 99.1

Gross margin should not be considered an alternative to operating (loss) income, net cash flows from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross margin presented by other companies may not be comparable to our presentation since each company may define this term differently. The following tables present a reconciliation of gross margin to the most directly comparable GAAP financial measure, operating (loss) income, on a historical basis for the periods indicated (in thousands):



	Year Ended December 31,
	2014			2013
Gross Margin
Refining and distribution	$	114,397		$	(4,909	)
Retail	44,523			9,452
Commodity marketing and logistics	5,649			16,666
Natural gas and oil	5,984			7,739
Total gross margin	170,553			28,948
Operating expense, excluding depreciation, depletion, and amortization expense	140,900			27,251
Lease operating expense	5,673			5,676
Depreciation, depletion, and amortization	14,897			5,982
Loss (gain) on sale of assets, net	624			(50		)
Trust litigation and settlements	—			6,206
General and administrative expense	34,304			21,494
Acquisition and integration costs	11,687			9,794
Total operating expenses	208,085			76,353
Operating loss	$	(37,532	)	$	(47,405	)

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

The 2014 and 2013 periods lack comparability due the acquisition of HIE on September 25, 2013.

Refining and Distribution Gross Margin. For the year ended December 31, 2014, our refining and distribution gross margin was approximately $114.4 million, an increase of $119.3 million compared to a loss of $4.9 million for the year ended December 31, 2013. The increase is primarily due to the acquisition of HIE in September 2013.

Retail Gross Margin. For the year ended December 31, 2014, our retail gross margin was approximately $44.5 million, an increase of $35.1 million compared to $9.5 million for the year ended December 31, 2013. The increase is primarily due to the acquisition of HIE in September 2013.

Commodity, Marketing and Logistics Gross Margin. For the year ended December 31, 2014, our commodity, marketing, and logistics gross margin was approximately $5.6 million, a decrease of $11.0 million when compared to $16.7 million for the year ended December 31, 2013. The decrease is primarily due to lower trading differentials on heavy Canadian crude oil and lower volumes.

Natural Gas and Oil Gross Margin. For the year ended December 31, 2014, our natural gas and oil gross margin was approximately $6.0 million, a decrease of $1.8 million when compared to $7.7 million for the year ended December 31, 2013. The decrease is primarily related to lower realized prices.

Operating Expense. For the year ended December 31, 2014, operating expense was approximately $146.6 million, an increase of $113.6 million when compared to $32.9 million for the year ended December 31, 2013. The increase is primarily due to the acquisition of HIE in September 2013.

Depreciation, Depletion, and Amortization. For the year ended December 31, 2014, DD&A expense was approximately $14.9 million, an increase of $8.9 million compared to $6.0 million for the year ended December 31, 2013. The increase is primarily due to the acquisition of HIE in September 2013.

Exhibit 99.1

Loss (Gain) on Sale of Assets, Net. For the year ended December 31, 2014, the loss on the sale of assets, net, was approximately $624 thousand as a result of selling oilfield equipment within our natural gas and oil production segment. There was no significant activity during the year ended December 31, 2013.

Trust Litigation and Settlements. For the year ended December 31, 2014, there was no trust litigation and settlement expense, compared to $6.2 million for the year ended December 31, 2013. There was no significant activity occurring in the current year as we moved further away from the date of our emergence from bankruptcy.

General and Administrative Expense. For the year ended December 31, 2014, general and administrative expense was approximately $34.3 million, an increase of $12.8 million when compared to $21.5 million for the year ended December 31, 2013. The increase is primarily due to higher stock-based compensation expense and consulting expenses related to process improvements and the strengthening of internal controls.

Acquisition and Integration Costs. For the year ended December 31, 2014, acquisition and integration costs were approximately $11.7 million, an increase of $1.9 million when compared to $9.8 million for the year ended December 31, 2013. The increase is primarily due to costs incurred to exit the transition service agreement with Tesoro, further integration efforts related to the acquisition of HIE and approximately $7 million of Mid Pac related costs.

Interest Expense and Financing Costs, Net. For the year ended December 31, 2014, our interest expense and financing costs were approximately $19.8 million, which is comparable to $19.4 million for the year ended December 31, 2013.

Other Income (Expense), Net. For the year ended December 31, 2014, other expense was approximately $312 thousand, a decrease of $1.1 million when compared to other income of $758 thousand for the year ended December 31, 2013. Other income for the year ended December 31, 2013 included a franchise tax refund and income from a legal settlement that were both nonrecurring. There were no individually significant items in the current year.

Change in Value of Common Stock Warrants. For the year ended December 31, 2014, the change in value of common stock warrants resulted in a gain of approximately $4.4 million, a change of $14.6 million when compared to a loss of $10.2 million for the year ended December 31, 2013. During the year ended December 31, 2014, our stock price decreased, which resulted in a decrease in the value of the common stock warrants. Conversely, our stock price increased during the year ended December 31, 2013, which resulted in a loss as the value of the common stock warrants also increased.

Change in Value of Contingent Consideration. For the year ended December 31, 2014, the change in value of contingent consideration was approximately $2.8 million. The contingent consideration relates to the acquisition of HIE which occurred on September 25, 2013, and the change in value is due to a decrease in our expected cash flows related to HIE during the contingency period.

Equity Earnings (Losses) From Piceance Energy, LLC. For the year ended December 31, 2014, earnings from Piceance Energy were approximately $2.8 million, a change of $5.8 million compared to a loss of $2.9 million for the year ended December 31, 2013. The favorable change is primarily due to higher realized natural gas prices and derivative gains.

Income Taxes. For the year ended December 31, 2014, we recorded approximately $455 thousand of state tax benefit. The 2014 effective tax rate of 1.0% differs from the statutory rate of 35% primarily due to a full valuation allowance against the tax benefit generated by our current operating loss and various state deferred tax activity. The 2013 effective tax rate was 0.0% and differed from the statutory rate primarily due to a full valuation allowance against the tax benefit generated by the operating loss.

Liquidity and Capital Resources

Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, fixed capacity payments and contractual obligations, capital expenditures and working capital needs. Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll. Our primary sources of liquidity are cash flows from operations, cash on hand, amounts available under our credit agreements, and access to capital markets.

Exhibit 99.1

The following table summarizes our liquidity position as of March 9, 2015 and December 31, 2014 (in thousands):



March 9, 2015	Refining and Distribution		Retail		Commodity Marketing and Logistics		Other		Total
Cash and cash equivalents	$	14,725	$	13,554	$	36,409	$	51,694	$	116,382
Revolver availability	—		5,000		—		—		5,000
ABL Facility	37,560		—		13,337		—		50,897
Total available liquidity	$	52,285	$	18,554	$	49,746	$	51,694	$	172,279



December 31, 2014	Refining and Distribution		Retail		Commodity Marketing and Logistics		Other		Total
Cash and cash equivalents	$	5,924	$	10,667	$	2,505	$	70,114	$	89,210
Revolver availability	—		5,000		—		—		5,000
ABL Facility	79,532		—		16,726		—		96,258
Total available liquidity	$	85,456	$	15,667	$	19,231	$	70,114	$	190,468

In addition to the above, in conjunction with our acquisition of HIE, and to finance the acquisition and the operations of the business of HIE after the acquisition, we entered into the crude oil Supply and Exchange Agreements. Generally, the primary uses of our capital resources have been in the acquisition and operation of Texadian and HIE, payment of operating expenses related to our natural gas and oil assets, professional fees, and bankruptcy expenses.

The decrease in liquidity from December 31, 2014 to March 9, 2015 for the refining and distribution segment is due to a decrease in our borrowing base as a result of the impact of falling refined product prices on our accounts receivable. The increase in the commodity marketing and logistics segment is the settlement of receivables in the normal course of business. The decrease in other liquidity is primarily due to the first payment of $13.5 million to fund our portion of Piceance's drill program and other operating activities. For more information, please read "Capital Expenditures" below.

In early April 2015, we expect to pay $97 million plus working capital in connection with the closing of the Mid Pac acquisition. We expect this will be funded from available cash on hand, additional debt issued by the Mid Pac subsidiary, and possible equity contributions from existing stockholders.

Rights Offering

In July 2014, we issued, at no charge, one transferable subscription right with respect to each share of our common stock then outstanding. Holders of subscription rights were entitled to purchase 0.21 shares of our common stock for each subscription right held at an exercise price of $16.00 per whole share. The rights offering was fully subscribed and we issued approximately 6.4 million shares of our common stock resulting in net proceeds of approximately $101.5 million in August 2014.

Term Loan

On May 30, 2014, we entered into a Twelfth Amendment to the Delayed Draw Term Loan Credit Agreement (the "Twelfth Amendment" and collectively the "Tranche B Loan"), with WB Macau55 Ltd. ("Tranche B Lender"), pursuant to which we borrowed an additional $13.2 million which was primarily used to fund the deposit due upon signing the merger agreement with Koko'oha as discussed in Note 4—Acquisitions.

The Twelfth Amendment provides that the Tranche B Loan bears interest (a) from May 30, 2014 to September 1, 2014 at a rate equal to 12% per annum payable in kind and (b) on and after September 1, 2014 at a rate equal to 14.75% per annum payable, at our election, either (i) in cash or (ii) in kind. We agreed to pay a nonrefundable amendment fee of approximately $506 thousand to the Tranche B Lender as well as an original issue discount of approximately $630 thousand. The Tranche B Lender agreed to waive the exit fee related to the existing Tranche B Loan of which we had accrued approximately $97 thousand as of the date of the Twelfth Amendment. Except as discussed above, the Twelfth Amendment did not change any other terms or conditions of the Tranche B Loan.

On July 11, 2014, we entered into a Delayed Draw Term Loan and Bridge Loan Credit Agreement ("Credit Agreement") to provide us with a term loan of up to $50 million ("Term Loan") and a bridge loan of up to $75 million ("Bridge Loan"). The

Exhibit 99.1

Term Loan amended and restated the Tranche B Loan, reduced the interest rate, and may be used to fund the additional deposit called for by the Mid Pac merger agreement, for transaction costs and for working capital and general corporate purposes. The Term Loan matures on July 11, 2018 and bears interest at either 10% per annum if paid in cash or 12% per annum if paid in kind, at our election, and has an original issue discount of 5%. During July 2014, we made two Term Loan draws in the amounts of $10.5 million and $5 million to fund transaction costs, general working capital, and corporate purposes.

On July 28, 2014, we entered into a First Amendment to the Credit Agreement pursuant to which we expanded the Term Loan and borrowed an additional $35 million ("Advance"), which resulted in net proceeds to us of approximately $32 million. The Advance was to be repaid upon the receipt of net equity proceeds from the rights offering discussed above. Except for the repayment terms, all other terms and conditions remained unchanged. We used the proceeds for working capital and general corporate purposes.

Please read Note 10—Debt for additional information.

Cash Flows

The following table summarizes cash activities for the year ended December 31, 2014 (in thousands):



	Year Ended December 31,
	2014			2013
Net cash used in operating activities	$	(54,604	)	$	(35,677	)
Net cash used in investing activities	$	(24,299	)	$	(564,500	)
Net cash provided by financing activities	$	130,052		$	632,053

Net cash used in operating activities was approximately $54.6 million for the year ended December 31, 2014 which resulted from a net loss of approximately $47.0 million offset by non-cash charges to operations of approximately $25.8 million and net cash used for changes in operating assets and liabilities of approximately $33.4 million. Net cash used in operating activities was approximately $35.7 million for the year ended December 31, 2013 which resulted from a net loss of approximately $79.2 million offset by non-cash charges to operations of approximately $37.1 million and net cash used for changes in operating assets and liabilities of approximately $6.4 million.

For the year ended December 31, 2014, net cash used in investing activities was approximately $24.3 million and primarily related to the Mid Pac acquisition deposit of $10.0 million and additions to property and equipment totaling approximately $14.3 million. Net cash used in investing activities was approximately $564.5 million for the year ended December 31, 2013 and was primarily related to the acquisition of HIE for approximately $559.3 million and net additions to property and equipment totaling approximately $4.9 million.

Net cash provided by financing activities for the year ended December 31, 2014 was approximately $130.1 million and consisted primarily of proceeds from the sale of common stock totaling $103.9 million and $26.0 million of borrowings under the Term Loan which were used to fund the Mid Pac acquisition deposit and general corporate and working capital purposes. Net cash provided by financing activities for the year ended December 31, 2013 of approximately $632.1 million resulted from advances from our supply and exchange agreements totaling approximately $378.2 million, the sale of common stock totaling approximately $199.2 million, additional net borrowings of approximately $35.6 million, and the release of approximately $19.0 million from restricted cash held to secure letters of credit.

Capital Expenditures

Our capital expenditures excluding acquisitions for the year ended December 31, 2014 totaled approximately $16.6 million and were primarily related to our refinery and information technology systems. Our capital expenditure budget for 2015 ranges from $10 to $15 million and primarily relates to projects to improve our refinery reliability and efficiency plus approximately $28 million for investments in Piceance Energy.

Additional capital may be required to maintain our interests at our Point Arguello Unit offshore California, but production is not economic in the current low-price environment and we are not able to estimate the amount of any potential

Exhibit 99.1

capital requirement.We also continue to seek strategic investments in business opportunities, but the amount and timing of those investments are not predictable.

Commitments and Contingencies

Supply and Exchange Agreements

HIE entered into several agreements with Barclays Bank PLC (“Barclays”), referred to collectively as the Supply and Exchange Agreements, on September 25, 2013 in connection with the acquisition of HIE for the purpose of managing our working capital and the crude oil and refined product inventory at the refinery.

Pursuant to the Supply and Exchange Agreements, Barclays holds title to all of the crude oil in the tanks at the refinery and holds title to a majority of our refined product inventory in our tanks at the refinery. Barclays also prepaid us for certain inventory held at locations outside our refinery. We hold title to the inventory during the refining process. Barclays sells the crude oil to us as it is discharged out of the refinery’s tanks. We exchange refined product owned by Barclays stored in our tanks for equal volumes of refined product produced by our refinery when we execute third-party sales of refined product. We currently market and sell the refined product independently to third parties. The Supply and Exchange Agreements have an initial term of three years with two one-year renewal options.

As described in Note 2—Summary of Significant Accounting Policies, we record the inventory owned by Barclays on our behalf because we maintain the risk of loss until the refined products are sold to third parties. Because we do not hold legal title to the crude oil inventory until it enters the refinery, we record a liability in an amount equal to the carrying value of the crude oil inventory. In accordance with the terms of the Supply and Exchange Agreements, the volume of refined products purchased by Barclays in connection with the acquisition of HIE is known as the “Block Volume”. To the extent we have refined products inventory equal to or in excess of the Block Volume at period end, we record a liability, valued at the carrying value of the related inventory, for only the Block Volume. To the extent we have refined product inventory less than the Block Volume at period-end, we record a liability for the refined product inventory on hand at its carrying value, plus a liability for the shortfall in volumes valued at current market prices. The liability related to the Supply and Exchange Agreements is included in Obligations under supply and exchange agreements on our consolidated balance sheets.

Environmental Matters

Like other petroleum refiners and oil and gas exploration and production companies, 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.

Regulation of Greenhouse Gases. The United States Environmental Protection Agency (“EPA”) has begun regulating GHG under the Clean Air Act Amendments of 1990 (“Clean Air Act”). 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.

Exhibit 99.1

which GHG emissions were reported to the EPA under 40 CFR Part 98). Those rules are pending final approval by the Government of Hawaii. The refinery’s capacity to reduce fuel use and GHG emissions is limited. However, the state’s pending regulation allows, and the refinery should be able to demonstrate, that additional reductions are not cost-effective or necessary in light of the state’s current GHG inventory and future year projection. The pending 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.

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 United States by model year 2020, and contained a second Renewable Fuel Standard (“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, the RSF2 will be satisfied primarily with fuel ethanol blended into gasoline. The RSF2 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.

In October 2010, the EPA issued a partial waiver decision under the Clean Air Act 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. In January 2011, the EPA issued a second waiver for the use of E15 in vehicles model year 2001-2006. 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. Since April 2006, the State of Hawaii has required that a minimum of 9.2% ethanol be blended into at least 85% of the gasoline pool, but the regulation also limited the amount of ethanol to no more than 10%. Consequently, unless either the state or federal regulations are revised, qualified Renewable Identification Numbers (“RINS”) will be required to fulfill the federal mandate for 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. Along with credit and trading options, potential capital upgrades for the refinery are being evaluated. The American Petroleum Institute and American Fuel and Petrochemical Association may challenge the final regulation. On December 30, 2014, HIE filed an application with the EPA to qualify as a Small Volume Refinery, which if approved would extend the compliance deadline three years until January 31, 2020 and provide more opportunities to create, acquire and use sulfur credits as a means of demonstrating compliance with Tier 3. Recognition and approval as a Small Volume Refinery under Tier 3 would not constrain rates nor be invalidated by future throughput rates that exceed the threshold criteria of 75,000 bpd on an annual aggregate basis.

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.

Environmental Agreement

On September 25, 2013 (“Closing Date”), Hawaii Pacific Energy (a wholly-owned subsidiary of Par created for purposes of the acquisition of HIE), Tesoro, and HIE entered into an Environmental Agreement (“Environmental Agreement”), which allocated responsibility for known and contingent environmental liabilities related to the acquisition of HIE, including the Consent Decree as described below.

Consent Decree. Tesoro is currently negotiating a Consent Decree with the EPA and the United States Department of Justice 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, including our refinery. It is anticipated that the Consent Decree will be

Exhibit 99.1

finalized sometime during the first half of 2015 and will require certain capital improvements to our refinery to reduce emissions of air pollutants.

We estimate the cost of compliance with the final Consent Decree could be $20 million to $25 million. However, Tesoro is responsible under the Environmental Agreement for reimbursing HIE 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 HIE arising from the Consent Decree to the extent related to acts or omission of Tesoro or HIE prior to the Closing Date. Tesoro’s obligation to reimburse HIE 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.

Tank Replacements. Tesoro replaced, at its expense, the existing underground storage tanks at certain retail locations. Please read Note 12—Commitments and Contingencies for additional 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 breached 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 HIE prior to the Closing Date, certain groundwater remediation work, the replacement of underground storage tanks located at certain retail assets, and fines or penalties imposed on HIE by the Consent Decree related to acts or omissions of Tesoro prior to the Closing Date and to the Pearl City Superfund Site.

Bankruptcy Matters

On the date we emerged from bankruptcy ("Emergence Date"), we formed the Delta Petroleum General Recovery Trust (“General Trust”). The General Trust was formed to pursue certain litigation against third parties, including preference actions, fraudulent transfer and conveyance actions, rights of setoff and other claims, 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 million each pursuant to the Plan.

The General Trust is pursuing all bankruptcy causes of action, claim objections and resolutions, and all other responsibilities for winding up the bankruptcy. The General Trust is overseen by a three-person General Trust Oversight Board and our Chief Legal Officer is currently the trustee (“Recovery Trustee”). Costs, expenses, and obligations incurred by the General Trust are charged against assets in 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.

The Plan provides that certain allowed general unsecured claims be paid with shares of our common stock. 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.

As of December 31, 2014, 27 claims totaling approximately $26.5 million remain to be resolved by the trustee for the General Trust and 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. During the year ended December 31, 2014, the trustee for the General Trust settled one claim from U.S. Bank for $3.7 million. In October 2014, we issued 146 thousand shares of common stock to settle this claim. During the year ended December 31, 2013, the trustee for the General Trust settled 59 claims for $26.9 million for approximately $5.4 million in cash and 209 thousand shares of common stock.

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,

Exhibit 99.1

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 a 2.41934% working interest in the unit.

Operating Leases

Within our refining and distribution segment and our retail segment, we have various cancellable and noncancellable operating leases related to land, vehicles, office and retail facilities, and other facilities used in the storage, transportation, and sale of crude oil and refined products. The majority of the future lease payments relate to retail stations and facilities used in the storage, transportation, and sale of crude oil and refined products. We have operating leases for most of our retail stations with primary terms of up to 32 years, and generally containing renewal options and escalation clauses. Leases for facilities used in the storage, transportation, and sale of crude oil and refined products have various expiration dates extending to 2027.

In addition, with our commodity marketing, and logistics segment, we have various agreements to lease storage facilities, primarily along the Mississippi River, railcars, inland river tank barges and towboats, and other equipment. These leasing agreements have been classified as operating leases for financial reporting purposes and the related rental fees are charged to expense over the lease term as they become payable. The leases generally range in duration of five years or less and contain lease renewal options at fair value. Our railcar leases contain an empty mileage indemnification provision whereby if the empty mileage exceeds the loaded mileage, we are charged for the empty mileage at the rate established by the tariff of the railroad on which the empty miles accrued.

Minimum annual lease payments extending to 2027 for operating leases to which we are legally obligated and having initial or remaining noncancellable lease terms in excess of one year are as follows (in thousands):



	Total
2015	$	28,944
2016	13,263
2017	11,224
2018	9,902
2019	7,954
Thereafter	18,194
Total minimum rental payments	$	89,481

Capital Leases

Within our retail segment, we have capital lease obligations related primarily to the leases of five retail stations with initial terms of 17 years, with four 5-year renewal options. Minimum annual lease payments including interest, for capital leases are as follows (in thousands):



2015	$	382
2016	382
2017	382
2018	420
2019	420
Thereafter	—
Total minimum lease payments	$	1,986
Less amount representing interest	460
Total minimum rental payments	$	1,526

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations were based on the consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 2—Summary of Significant Accounting Policies of our audited consolidated financial statements included herein. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We

Exhibit 99.1

analyze our estimates on a periodic basis, including those related to fair value, impairments, natural gas and oil reserves, bad debts, natural gas and oil properties, income taxes, derivatives, contingencies, and litigation, and base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.

Inventory

Inventories are stated at the lower of cost or market value using the first-in, first-out accounting method. We value merchandise along with spare parts, materials and supplies at average cost.

Our refining and distribution segment acquires substantially all of its crude oil from Barclays Bank PLC (“Barclays”) under supply and exchange agreements as described in Note 9—Supply and Exchange Agreements. The crude oil remains in the legal title of Barclays and is stored in our storage tanks governed by a storage agreement. Legal title to the crude oil passes to us at the tank outlet. After processing, Barclays takes title to the refined products stored in our storage tanks until sold to our retail locations or to third parties. We record the inventory owned by Barclays on our behalf as inventory with a corresponding accrued liability on our balance sheet because we maintain the risk of loss until the refined products are sold to third parties.

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. In estimating fair value, we use discounted cash-flow projections, recent comparable market transactions, if available, or quoted prices. We consider assumptions that third parties would make in estimating fair value, including the highest and best use of the asset. The assumptions used by another party could differ significantly from our assumptions.

We classify fair value balances based on the classification of the inputs used to calculate the fair value of a transaction. The inputs used to measure fair value have been placed in a hierarchy based on priority. The hierarchy gives the highest priority to unadjusted, readily observable quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. We use a variety of methods to estimate the fair value of assets and liabilities acquired in business combinations and evaluating goodwill and other long-lived assets for impairment. These methods include the cost approach, the sales approach, and the income approach. These methods require management to make judgments regarding characteristics of the acquired property, future revenues and expenses. There is a significant amount of judgment involved in cash-flow estimates. Changes in these estimates would result in different amounts allocated to the related assets and liabilities.

Assets and Liabilities Recorded at Fair Value on a Recurring Basis. In the valuation of the liability for the contingent consideration to be paid for the acquisition of HIE and of our outstanding warrants, we use a Monte Carlo simulation model which requires management to make estimates of future gross margin, gross margin volatility and expected volatility of our stock price, and a present value factor. Different estimates would result in a change in the fair value of the amounts presented in our consolidated financial statements.

Additionally, we have certain derivative instruments where we have elected the normal purchases and normal sales exception. Had we not made this election, these derivatives would be marked to market each period with the difference recorded in earnings.

Derivatives and Other Financial Instruments. We periodically enter into commodity price risk transactions to manage our exposure to natural gas and oil price volatility. These transactions may take the form of non-exchange traded fixed price forward contracts and exchange traded futures contracts, collar agreements, swaps, or options. The purpose of the transactions will be to provide a measure of stability to our cash flows in an environment of volatile commodity prices.

As of and for the year ended December 31, 2014, we have elected the normal purchase normal sale exemption for all outstanding commodity contracts. As a result, we did not recognize the unrealized gains or losses related to these contracts in our consolidated financial statements. Should we not designate a contract as a normal purchase or normal sale then the contract would

Exhibit 99.1

be accounted for at fair value on our consolidated balance sheets and marked to market each reporting period with changes in fair value being reflected in earnings.

In addition, from time to time we may have other financial instruments, such as warrants or embedded debt features, that may be classified as liabilities when either (a) the holders possess rights to net cash settlement, (b) physical or net equity settlement is not in our control, or (c) the instruments contain other provisions that cause us to conclude that they are not indexed to our equity. Such instruments are initially recorded at fair value and subsequently adjusted to fair value at the end of each reporting period through earnings.

In connection with our emergence from bankruptcy, we issued warrants that are not considered to be indexed to our equity. Accordingly, these warrants are accounted for as liabilities. In addition, our former delayed draw term loan facility contained certain puts that were required to be accounted for as embedded derivatives. The warrant liabilities and embedded derivatives are accounted for at fair value with changes in fair value reflected in earnings.

Income Taxes

We use the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. The realizability of deferred tax assets is evaluated quarterly based on a “more likely than not” standard, and to the extent this threshold is not met, a valuation allowance is recorded.

We recognize the impact of an uncertain tax position only if it is more likely than not of being sustained upon examination by the relevant taxing authority based on the technical merits of the position. As a general rule, our open years for Internal Revenue Service (“IRS”) examination purposes are 2011, 2012 and 2013. However, since we have net operating loss carryforwards, the IRS has the ability to make adjustments to items that originate in a year otherwise barred by the statute of limitations under Section 6501 of the Internal Revenue Code of 1986, as amended (the “Code”), in order to re-determine tax for an open year to which those items are carried. Therefore, in a year in which a net operating loss deduction is claimed, the IRS may examine the year in which the net operating loss was generated and adjust it accordingly for purposes of assessing additional tax in the year the net operating loss deductions was claimed. Any penalties or interest as a result of an examination will be recorded in the period assessed.

We expect to incur state income tax liabilities as a result of certain operations in states where we have no net operating loss carryovers available to offset taxable income generated within those states.

Revenue Recognition

We recognize revenue when it is realized or realizable and earned. Revenue is realized or realizable and earned when persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the price to the buyer is fixed or determinable, and collectibility is reasonably assured. Revenue that does not meet these criteria is deferred until the criteria are met.

Refining and Distribution. We recognize revenues upon delivery of goods or services to a customer. For goods, this is the point at which title is transferred and when payment has either been received or collection is reasonably assured. Revenues for services are recorded when the services have been provided. We record certain transactions in Cost of revenues in our consolidated statements of operations on a net basis, including nonmonetary crude oil and refined product exchange transactions used to optimize our refinery supply, and sale and purchase transactions entered into with the same counterparty that are deemed to be in contemplation with one another. We include transportation fees charged to customers in Revenues in our consolidated statements of operations, while the related transportation costs are included in Cost of revenues or operating expenses.

Retail. We recognize revenues upon delivery of goods or services to a customer. For goods, this is the point at which title is transferred and when payment has either been received or collection is reasonably assured. Federal excise and state motor fuel taxes, which are remitted to governmental agencies are excluded from both Revenues and Cost of revenues in our consolidated statements of operations.

Exhibit 99.1

regardless of whether the sales are proportionate to our ownership in the property. A liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2014 and 2013, our aggregate natural gas and oil imbalances were not material to our consolidated financial statements.

Commodity Marketing and Logistics. We earn revenues from the sale and transportation of oil and the rental of railcars. Accordingly, revenues and related costs from sales of oil are recorded when title transfers to the buyer. Transportation revenues are recognized when title passes to the customer, which is when risk of ownership transfers to the customer, and physical delivery occurs. Revenues from the rental of railcars are recognized ratably over the lease periods.

Asset Retirement Obligations

We record asset retirement obligations (“AROs”) at fair value in the period in which we have a legal obligation, whether by government action or contractual arrangement, to incur these costs and can make a reasonable estimate of the fair value of the liability. Our AROs arise from our refining and distribution business and from our retail operations, as well as plugging and abandonment of wells within our natural gas and oil operations. AROs are calculated based on the present value of the estimated removal and other closure costs using our credit-adjusted risk-free rate. When the liability is initially recorded, we capitalize the cost by increasing the book value of the related long-lived tangible asset. The liability is accreted to its estimated settlement value and the related capitalized cost is depreciated over the asset’s useful life and both expenses are recorded in Depreciation, depletion and amortization in the consolidated statements of operations. We recognize a gain or loss at settlement for any difference between the settlement amount and the recorded liability, which is recorded as a loss on asset disposals and impairments in our consolidated statements of operations. We estimate settlement dates by considering our past practice, industry practice, management’s intent and estimated economic lives.

We cannot currently estimate the fair value for certain AROs primarily because we cannot estimate settlement dates (or ranges of dates) associated with these assets. These AROs include hazardous materials disposal (such as petroleum manufacturing by-products, chemical catalysts, and sealed insulation material containing asbestos), and removal or dismantlement requirements associated with the closure of our refining facility, terminal facilities, or pipelines, including the demolition or removal of certain major processing units, buildings, tanks, pipelines, or other equipment.

Exhibit 99.1

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Par Petroleum Corporation

Houston, Texas

We have audited the accompanying consolidated balance sheets of Par Petroleum Corporation and subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits. We did not audit the financial statements of Piceance Energy, LLC, an equity method investee of the Company. The Company’s investment in Piceance Energy, LLC constitutes 14% and 13% of consolidated total assets as of December 31, 2014 and 2013, respectively, and the Company’s interest in the net income (loss) of Piceance Energy, LLC constitutes 6% and 4% of consolidated net loss for the years ended December 31, 2014 and 2013, respectively. The financial statements of Piceance Energy, LLC were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Piceance Energy, LLC, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of the other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of Par Petroleum Corporation and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 12, 2015 (May 22, 2015 as to the effects of the change in segments described in Note 17)

Exhibit 99.1

Report of Independent Registered Public Accounting Firm

To the Members of

Piceance Energy, LLC

Denver, Colorado

We have audited the accompanying balance sheets of Piceance Energy, LLC (the “Company”) as of December 31, 2014 and 2013, and the related statements of operations, members’ equity, and cash flows for the years ended December 31, 2014 and 2013, and the related notes to the financial statements (not separately included herein). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the PCAOB (United States of America). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Piceance Energy, LLC as of December 31, 2014 and 2013, and the results of its operations and its cash flows for the years ended December 31, 2014 and 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ EKS&H LLLP

EKS&H LLLP

February 27, 2015

Denver, Colorado

Exhibit 99.1

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share amounts)



	December 31,
	2014			2013
ASSETS
Current assets
Cash and cash equivalents	$	89,210		$	38,061
Restricted cash	749			802
Trade accounts receivable	112,968			117,493
Inventories	243,853			380,623
Prepaid and other current assets	14,009			7,522
Total current assets	460,789			544,501
Property and equipment
Property, plant and equipment	123,323			107,623
Proved oil and gas properties, at cost, successful efforts method of accounting	1,122			4,949
Total property and equipment	124,445			112,572
Less accumulated depreciation, depletion and amortization	(11,510		)	(3,968		)
Property and equipment, net	112,935			108,604
Long-term assets
Investment in Piceance Energy, LLC	104,657			101,796
Intangible assets, net	7,506			11,170
Goodwill	20,786			20,603
Other long-term assets	34,334			26,539
Total assets	$	741,007		$	813,213
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	29,100		$	3,250
Obligations under supply and exchange agreements	197,394			385,519
Accounts payable	33,064			28,870
Other accrued liabilities	50,152			31,956
Accrued settlement claims	1,096			3,793
Total current liabilities	310,806			453,388
Long-term liabilities
Long-term debt, net of current maturities and unamortized discount	107,510			94,030
Common stock warrants	12,123			17,336
Contingent consideration	9,131			11,980
Long-term capital lease obligations	1,295			1,526
Other liabilities	7,983			6,689
Total liabilities	448,848			584,949
Commitments and contingencies (Note 12)
Stockholders’ equity
Preferred stock, $0.01 par value: 3,000,000 shares authorized, none issued	—			—
Common stock, $0.01 par value; 500,000,000 shares and 300,000,000 shares authorized at December 31, 2014 and 2013, respectively, 37,068,886 shares and 30,151,000 shares issued at December 31, 2014 and 2013, respectively	371			301
Additional paid-in capital	427,287			315,975
Accumulated deficit	(135,053		)	(88,012		)
Accumulated other comprehensive loss	(446		)	—
Total stockholders’ equity	292,159			228,264
Total liabilities and stockholders’ equity	$	741,007		$	813,213

See accompanying notes to consolidated financial statements.

Exhibit 99.1

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)



	Year Ended December 31,
	2014			2013
Revenues
Refining and distribution revenues	$	2,681,208		$	729,213
Retail revenues	231,673			48,913
Commodity marketing and logistics revenues	189,160			100,149
Natural gas and oil revenues	5,984			7,739
Total operating revenues	3,108,025			886,014
Operating expenses
Cost of revenues	2,937,472			857,066
Operating expense, excluding depreciation, depletion and amortization expense	140,900			27,251
Lease operating expense	5,673			5,676
Depreciation, depletion and amortization	14,897			5,982
Loss (gain) on sale of assets, net	624			(50		)
Trust litigation and settlements	—			6,206
General and administrative expense	34,304			21,494
Acquisition and integration expense	11,687			9,794
Total operating expenses	3,145,557			933,419
Operating loss	(37,532		)	(47,405		)
Other income (expense)
Interest expense and financing costs, net	(19,783		)	(19,426		)
Other income (expense), net	(312		)	758
Change in value of common stock warrants	4,433			(10,159		)
Change in value of contingent consideration	2,849			—
Equity earnings (losses) from Piceance Energy, LLC	2,849			(2,941		)
Total other income (expense), net	(9,964		)	(31,768		)
Loss before income taxes	(47,496		)	(79,173		)
Income tax benefit (expense)	455			—
Net loss	$	(47,041	)	$	(79,173	)
Basic and diluted loss per common share	$	(1.44	)	$	(4.01	)
Weighted average number of shares outstanding:
Basic	32,739			19,740
Diluted	32,739			19,740

See accompanying notes to consolidated financial statements.

Exhibit 99.1

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands, except per share amounts)



	Year Ended December 31,
	2014			2013
Net loss	$	(47,041	)	$	(79,173	)
Other comprehensive loss:
Other post-retirement benefits and total other comprehensive loss	(446		)	—
Comprehensive loss	$	(47,487	)	$	(79,173	)

See accompanying notes to consolidated financial statements.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2014			2013
Cash flows from operating activities:
Net loss	$	(47,041	)	$	(79,173	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion	14,897			5,982
Non-cash interest expense	15,258			16,742
Change in value of common stock warrants	(4,433		)	10,159
Change in value of contingent consideration	(2,849		)	—
Lower of cost or market charge	2,444			—
Deferred taxes	(257		)	179
Loss (gain) on sale of assets, net	624			(50		)
Stock-based compensation	3,970			1,161
Unrealized gain on derivative contracts	(1,015		)	—
Equity (earnings) losses from Piceance Energy, LLC	(2,849		)	2,941
Net changes in operating assets and liabilities:
Trade accounts receivable	5,608			(40,278		)
Prepaid and other assets	(5,966		)	(2,569		)
Inventories	59,085			69,211
Obligations under supply and exchange agreements	(112,884		)	(38,999		)
Accounts payable and other accrued liabilities	20,804			19,017
Net cash used in operating activities	(54,604		)	(35,677		)
Cash flows from investing activities
Payment of deposit for Koko'oha acquisition	(10,000		)	—
Capital expenditures	(14,300		)	(7,768		)
Proceeds from sale of assets	595			2,850
Purchase of HIE, net of cash acquired, including working capital settlement	(582		)	(559,279		)
Investment in Piceance Energy, LLC	(12		)	(303		)
Net cash used in investing activities	(24,299		)	(564,500		)
Cash flows from financing activities
Proceeds from sale of common stock, net of offering costs	103,949			199,170
Proceeds from borrowings	363,620			159,800
Repayments of borrowings	(331,530		)	(121,909		)
Payment of deferred loan costs	(6,045		)	(2,264		)
Proceeds from supply and exchange agreements	—			378,238
Proceeds from exercise of common stock warrants	5			18
Restricted cash released	53			19,000
Net cash provided by financing activities	130,052			632,053
Net increase in cash and cash equivalents	51,149			31,876
Cash at beginning of period	38,061			6,185
Cash at end of period	$	89,210		$	38,061
Supplemental cash flow information
Cash received (paid) for:
Interest	$	(4,526	)	$	(2,186	)
Taxes	$	243		—
Non-cash investing and financing activities
Accrued capital expenditures	$	2,328		$	—
Stock issued used to settle bankruptcy claims	$	2,677		$	2,605
Value of warrants reclassified to equity	$	786		$	3,741

See accompanying notes to consolidated financial statements.

Exhibit 99.1

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(in thousands)



				Additional						Accumulated Other
	Common Stock			Paid-In			Accumulated			Comprehensive			Total
	Shares	Amount		Capital			Deficit			Loss			Equity
Balance, January 1, 2013	15,008	$	150	$	109,446		$	(8,839	)	$	—		$	100,757
Issuance of common stock, net of offering costs of $830 thousand	14,388	144		199,026			—			—			199,170
Bankruptcy claim settlements	209	2		2,603			—			—			2,605
Exercise of common stock warrants	184	2		3,739			—			—			3,741
Share-based compensation	362	3		1,161			—			—			1,164
Net loss	—	—		—			(79,173		)	—			(79,173		)
Balance, December 31, 2013	30,151	301		315,975			(88,012		)	—			228,264
Reverse stock split	—	1		(1		)	—			—			—
Issuance of common stock, net of offering costs of $237 thousand	6,525	65		103,884			—			—			103,949
Bankruptcy claim settlements	146	1		2,676			—			—			2,677
Exercise of common stock warrants	51	1		785			—			—			786
Share-based compensation	196	2		3,968						—			3,970
Other comprehensive loss	—	—		—			—			(446		)	(446		)
Net loss	—	—		—			(47,041		)	—			(47,041		)
Balance, December 31, 2014	37,069	$	371	$	427,287		$	(135,053	)	$	(446	)	$	292,159

See accompanying notes to consolidated financial statements.

Exhibit 99.1

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Note 1—Overview

We are a diversified energy company based in Houston, Texas. Currently, we operate in four segments: (i) refining and distribution, (ii) retail, (iii) natural gas and oil production, and (iv) commodity marketing and logistics.

Our refining and distribution segment consists of a refinery in Kapolei, Hawaii, refined products terminals, pipelines, a single-point mooring and trucking operations. The refinery produces ultra-low sulfur diesel, gasoline, jet fuel, marine fuel, and other associated refined products primarily for consumption in Hawaii.

Our retail segment consists of retail outlets which sell gasoline, diesel, and retail merchandise throughout Hawaii. Our retail network includes Tesoro-branded retail sites, company-operated convenience stores, and other sites operated by third parties.

The refining and distribution and retail operations were established through the acquisition of Hawaii Independent Energy, LLC ("HIE") on September 25, 2013.

Our natural gas and oil production segment consists of natural gas and oil assets that are non-operated and are concentrated in our 33.34% ownership of Piceance Energy, LLC ("Piceance Energy"), a joint venture entity operated by Laramie Energy II, LLC ("Laramie") and focused on producing natural gas in Garfield and Mesa Counties, Colorado. In addition, we own non-operated interests in Colorado and offshore California, and an overriding royalty interest in New Mexico. Our interests are heavily weighted towards natural gas and natural gas liquids.

Our commodity marketing and logistics segment focuses on sourcing, marketing, transporting, and distributing crude oil and refined products. Our logistics capability consists of historical pipeline shipping status, a railcar fleet, and expertise in contracted chartering of tows and barges, with the capability of moving crude oil from landlocked locations in the Western U.S. and Canada to the refining hubs in the Midwest, Gulf Coast, and East Coast regions of the U.S.

As a result of the HIE acquisition, our results of operations for any period after September 30, 2013 will not be comparable to any prior period. We anticipate our results of operations, capital and liquidity position, and the overall success of our business will depend, in large part, on the results of our refining and distribution segment. The differences, or spread, between crude oil prices and the prices we receive for finished products (known as the “crack spread”), both of which are largely beyond our control, will be the primary driver of the refining and distribution segment results of operations and, therefore, of our profitability.

Note 2—Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Par Petroleum Corporation and its subsidiaries. All inter-company balances and transactions have been eliminated in consolidation.

Certain amounts previously reported in our consolidated financial statements for prior periods have been reclassified to conform to the current presentation.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Actual amounts could differ from these estimates. Significant estimates include the fair value of assets and liabilities, natural gas and oil reserves, income taxes and the valuation allowances related to deferred tax assets, derivatives, asset retirement obligations, and contingencies and litigation accruals.

Cash and Cash Equivalents

Cash and cash equivalents consist of all highly liquid investments with original maturities of three months or less. The carrying value of cash equivalents approximates fair value because of the short-term nature of these investments.

Restricted Cash

Restricted cash consists of cash not readily available for general purpose cash needs. Restricted cash relates to bankruptcy matters and cash held at commercial banks to support letter of credit facilities.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Allowance for Doubtful Accounts

We establish provisions for losses on trade receivables if it becomes probable we will not collect all or part of the outstanding balances. We review collectibility and establish or adjust our allowance as necessary using the specific identification method. As of December 31, 2014 and 2013, we had no significant allowance for doubtful accounts.

Inventories

Commodity inventories are stated at the lower of cost or market value using the first-in, first-out accounting method. We value merchandise along with spare parts, materials and supplies at average cost.

Investment in Piceance Energy, LLC

We account for our Investment in Piceance Energy, LLC using the equity method as we have the ability to exert significant influence, but do not control its operating and financial policies. Our proportionate share of net income (loss) of this entity is included in Equity earnings (losses) from Piceance Energy, LLC in the consolidated statements of operations. The investment is reviewed for impairment when events or changes in circumstances indicate that there has been an other than temporary decline in the value of the investment.

Property, Plant and Equipment

We capitalize the cost of additions, major improvements and modifications to property, plant, and equipment. The cost of repairs and normal maintenance of property, plant, and equipment is expensed as incurred. Major improvements and modifications of property, plant, and equipment are those expenditures that either extend the useful life, increase the capacity or improve the operating efficiency of the asset, or improve the safety of our operations. We compute depreciation of property, plant, and equipment using the straight-line method, based on the estimated useful life of each asset as follows:



Assets	Lives in Years
Refining	8 to 47
Logistics	3 to 30
Retail	14 to 18
Corporate	3 to 7
Software	3

We record property under capital leases at the lower of the present value of minimum lease payments using our incremental borrowing rate or the fair value of the leased property at the date of lease inception. We depreciate leasehold improvements and property acquired under capital leases over the shorter of the lease term or the economic life of the asset.

We review property, plant, and equipment and other long-lived assets whenever events or changes in business circumstances indicate the carrying value of the assets may not be recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. If this occurs, an impairment loss is recognized for the difference between the fair value and carrying value. Factors that indicate potential impairment include: a significant decrease in the market value of the asset, operating or cash flow losses associated with the use of the asset and a significant change in the asset’s physical condition or use.

Natural Gas and Oil Properties

We account for our natural gas and oil exploration and development activities using the successful efforts method of accounting. Under such method, costs of productive exploratory wells, development dry holes, and productive wells and undeveloped leases are capitalized. Natural gas and oil lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological or geophysical expenses, and delay rentals for natural gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, then evaluated quarterly and charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

Unproved properties are assessed quarterly on a property-by-property basis and any impairment in value is charged to expense. If the unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties and are depleted. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain or loss until all costs have been recovered.

Depreciation, depletion, and amortization ("DD&A") of capitalized acquisition, exploration, and development costs is computed using the units-of-production method by individual fields (common reservoirs) using proved producing natural gas and oil reserves as the related reserves are produced. Associated leasehold costs are depleted using the unit-of-production method based on total proved natural gas and oil reserves as the related reserves are produced.

Our natural gas and oil assets are reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

Asset Retirement Obligations

We record asset retirement obligations (“AROs”) in the period in which we have a legal obligation, whether by government action or contractual arrangement, to incur these costs and can make a reasonable estimate of the liability. Our AROs arise from our refining and distribution business and from our retail operations, as well as plugging and abandonment of wells within our natural gas and oil operations. AROs are calculated based on the present value of the estimated removal and other closure costs using our credit-adjusted risk-free rate. When the liability is initially recorded, we capitalize the cost by increasing the book value of the related long-lived tangible asset. The liability is accreted to its estimated settlement value with accretion expense recognized in DD&A on our consolidated statement of operations and the related capitalized cost is depreciated over the asset’s useful life. We recognize a gain or loss at settlement for any difference between the settlement amount and the recorded liability, which is recorded as a loss on asset disposals and impairments in our consolidated statements of operations. We estimate settlement dates by considering our past practice, industry practice, contractual terms, management’s intent and estimated economic lives.

We cannot currently estimate the fair value for certain AROs primarily because we cannot estimate settlement dates (or range of dates) associated with these assets. These AROs include hazardous materials disposal (such as petroleum manufacturing by-products, chemical catalysts, and sealed insulation material containing asbestos), and removal or dismantlement requirements associated with the closure of our refining facility, terminal facilities, or pipelines, including the demolition or removal of certain major processing units, buildings, tanks, pipelines or other equipment.

Goodwill and Other Intangible Assets

Goodwill represents the amount the purchase price exceeds the fair value of net assets acquired in a business combination. Goodwill is not amortized, but is tested for impairment annually on October 1. We assess the recoverability of the carrying value of goodwill during the fourth quarter of each year or whenever events or changes in circumstances indicate that the carrying amount of the goodwill of a reporting unit may not be fully recoverable. We first assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying value. If the qualitative assessment indicates that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a two-step quantitative test is required. If required, we will review the carrying value of the net assets of the reporting unit to the estimated fair value of the reporting unit. If the carrying value exceeds the estimated fair value of the reporting unit, an impairment indicator exists and an estimate of the impairment loss is calculated.

Our intangible assets include relationships with suppliers and shippers, favorable railcar leases, trade names, and trademarks. These intangible assets will be amortized over their estimated useful lives on a straight line basis. We evaluate the carrying value of our intangible assets when impairment indicators are present. When we believe impairment indicators may exist, projections of the undiscounted future cash flows associated with the use of and eventual disposition of the intangible assets are prepared. If the projections indicate that their carrying values are not recoverable, we reduce the carrying values to their estimated fair values.

Environmental Matters

We capitalize environmental expenditures that extend the life or increase the capacity of facilities as well as expenditures that prevent environmental contamination. We expense costs that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation. We record liabilities when environmental assessments and/or remedial efforts are probable and can be reasonably estimated. Cost estimates are based on the expected timing and extent of remedial

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

actions required by governing agencies, experience gained from similar sites for which environmental assessments or remediation have been completed, and the amount of our anticipated liability considering the proportional liability and financial abilities of other responsible parties. Usually, the timing of these accruals coincides with the completion of a feasibility study or our commitment to a formal plan of action. Estimated liabilities are not discounted to present value and environmental expenses are recorded in operating expenses in our consolidated statements of operations.

Derivatives and Other Financial instruments

We periodically enter into commodity price risk transactions to manage our exposure to natural gas and oil price volatility. These transactions may take the form of non-exchange traded fixed price forward contracts and exchange-traded futures contracts, collar agreements, swaps, or options. The purpose of the transactions is to provide a measure of stability to our cash flows in an environment of volatile commodity prices.

Our commodity marketing and logistics segment enters into fixed-price forward purchase and sale contracts for crude oil. The contracts typically contain settlement provisions in the event of a failure of either party to fulfill its commitments under the contract. Our policy is to fulfill or accept the physical delivery of the product, even if shipment is delayed, and will not net settle. Should we not designate a contract as a normal purchase or normal sale, the contract would be accounted for at fair value on our consolidated balance sheets and marked to market each reporting period with changes in fair value being charged to earnings. As of December 31, 2014 and 2013, we have elected the normal purchase normal sale exemption for all outstanding contracts. As a result, we did not recognize the unrealized gains or losses related to these contracts in our consolidated financial statements.

Please read Note 10—Debt and Note 11—Fair Value Measurements for information regarding our common stock warrants which are accounted for as liabilities. In addition, our former delayed draw term loan facility contained certain puts that were accounted for as embedded derivatives.

Accrued Settlement Claims

We accrued an estimate of the settlement liability relating to claims resulting from our bankruptcy. Please read Note 12—Commitments and Contingencies for further information.

Income Taxes

We recognize the impact of an uncertain tax position only if it is more likely than not of being sustained upon examination by the relevant taxing authority based on the technical merits of the position. As a general rule, our open years for Internal Revenue Service (“IRS”) examination purposes are 2011, 2012, and 2013. However, since we have net operating loss carryforwards, the IRS has the ability to make adjustments to items that originate in a year otherwise barred by the statute of limitations in order to re-determine tax for an open year to which those items are carried. Therefore, in a year in which a net operating loss deduction is claimed, the IRS may examine the year in which the net operating loss was generated and adjust it accordingly for purposes of assessing additional tax in the year the net operating loss deductions was claimed. Any penalties or interest as a result of an examination will be recorded in the period assessed.

Stock Based Compensation

We recognize the cost of share-based payments over the period the employee provides service, generally the vesting period, and include such costs in General and administrative expense in the consolidated statements of operations. The fair value

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

of equity instruments issued to employees is measured on the grant date and recognized over the service period on a straight-line basis.

Revenue Recognition

We recognize revenue when it is realized or realizable and earned. Revenue is realized or realizable and earned when persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the price to the buyer is fixed or determinable, and collectability is reasonably assured. Revenue that does not meet these criteria is deferred until the criteria are met.

Certain transactions include sale and purchase transactions entered into with the same counterparty that are deemed to be in contemplation with one another and are recorded on a net basis and included in Cost of revenues on our consolidated statements of operations.

Refining and Distribution. We recognize revenues upon delivery of goods or services to a customer. For goods, this is the point at which title and risk of loss is transferred and when payment has either been received or collection is reasonably assured. Revenues for services are recorded when the services have been provided. We include transportation fees charged to customers in Revenues in our consolidated statements of operations, while the related transportation costs are included in Cost of revenues.

Retail. We recognize revenues upon delivery of goods or services to a customer. For goods, this is the point at which title and risk of loss is transferred and when payment has either been received or collection is reasonably assured. Federal excise and state motor fuel taxes, which are collected from customers and remitted to governmental agencies within our retail segment are excluded from both Revenues and Cost of revenues in our consolidated statements of operations.

Natural Gas and Oil. Revenues are recognized when title to the products transfers to the purchaser. We follow the “sales method” of accounting for our natural gas and oil revenue and recognize sales revenue on all natural gas or oil sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. A liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2014 and 2013, our aggregate natural gas and oil imbalances were not material to our consolidated financial statements.

Commodity Marketing and Logistics. We earn revenues from the sale and transportation of oil and the rental of railcars. Accordingly, revenues and related costs from sales of oil are recorded when title transfers to the buyer. Transportation revenues are recognized when title passes to the customer, which is when risk of ownership transfers to the purchaser, and physical delivery occurs. Revenues from the rental of railcars are recognized ratably over the lease periods.

Other Post-retirement Benefits - Medical

We recognize an asset for the overfunded status or a liability for the underfunded status of its post-retirement benefit plan. The funded status is recorded within Other long-term liabilities. Changes in the plan's funded status are recognized in Other comprehensive loss in the period the change occurs.

Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are categorized with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority given to unobservable inputs. The three levels of the fair value hierarchy are as follows:


Level 1 –	Assets or liabilities for which the item is valued based on quoted prices (unadjusted) for identical assets or liabilities in active markets.


Level 2 –	Assets or liabilities valued based on observable market data for similar instruments.


Level 3 –	Assets or liabilities for which significant valuation assumptions are not readily observable in the market; instruments valued based on the best available data, some of which is internally-developed, and considers risk premiums that a market participant would require.

The level in the fair value hierarchy within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

the fair value hierarchy levels. Our policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. We have consistently applied these valuation techniques for the periods presented. We use data from peers as well as external sources in the determination of the volatility and risk free rates used in our fair value calculations. A sensitivity analysis is performed as well to determine the impact of inputs on the ending fair value estimate.

Loss Per Share

Basic loss per share (“EPS”) is computed by dividing net loss by the sum of the weighted average number of common shares outstanding and the weighted average number of shares issuable under the warrants. Please read Note 15—Loss Per Share for further information. The warrants are included in the calculation of basic EPS because they are issuable for minimal consideration. Non-vested restricted stock is excluded from the computation of basic EPS as these shares are not considered earned until vesting occurs.

Foreign Currency Transactions

We may, on occasion, enter into transactions denominated in currencies other than the U. S. dollar, our functional currency. Gains and losses resulting from changes in currency exchange rates between the functional currency and the currency in which a transaction is denominated are included in Other income (expense), net, in the accompanying consolidated statement of operations in the period in which the currency exchange rates change.

Accounting Principles Not Yet Adopted

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”). The FASB’s objective was to provide a more robust framework to improve comparability of revenue recognition practices across entities by removing most industry and transaction specific guidance, align GAAP with International Financial Reporting Standards, and provide more useful information to financial statement users. This authoritative guidance changes the way entities recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. ASU No. 2014-09 is effective for interim and annual periods beginning after December 15, 2016 and early adoption is not permitted. We are in the process of determining the impact this guidance will have on our financial condition, results of operations and cash flows.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 is intended to define management’s responsibility to evaluate whether there is substantial doubt about an organization’s ability to continue as a going concern and to provide related footnote disclosures. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2016 and early adoption is permitted. We do not expect the adoption of ASU 2014-15 to have a material impact on our financial condition, results of operations and cash flows.

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis ("ASU 2015-02"). ASU 2015-02 changes the consolidation analysis required under U.S.generally accepted accounting principles. ASU 2015-02 eliminates the presumption that a general partner should consolidate a limited partnership and modifies the evaluation of whether limited partnerships are Variable Interest Entities ("VIEs") or voting interest entities. Under the amended guidance, limited partners would be required to consolidate a partnership if the limited partner retains certain powers and obligations. The amendments in this ASU are effective for annual periods beginning after December 15, 2016, and interim periods beginning after December 15, 2017. Early adoption is permitted, but the guidance must be applied as of the beginning of the annual period containing the adoption date. We are in the process of determining the impact this guidance will have on our financial condition, results of operations and cash flows.

Note 3—Investment in Piceance Energy

We have a 33.34% ownership interest in Piceance Energy, LLC ("Piceance Energy"), a joint venture operated by Laramie Energy II, LLC ("Laramie") and focused on producing natural gas in Garfield and Mesa Counties, Colorado. Piceance Energy has a $400 million revolving credit facility secured by a lien on its natural gas and oil properties and related assets with a borrowing base currently set at $125 million. As of December 31, 2014 and 2013, the balance outstanding on the revolving credit facility was approximately $98 million and $90.2 million, respectively. We are guarantors of Piceance Energy’s credit facility, with recourse limited to the pledge of our equity interest of our wholly-owned subsidiary, Par Piceance Energy Equity. Under the terms of its credit facility, Piceance Energy is generally prohibited from making future cash distributions to its owners, including us.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

The change in our equity investment in Piceance Energy is as follows (in thousands):



	Year Ended December 31,
	2014		2013
Beginning balance	$	101,796	$	104,434
Equity earnings (loss) from Piceance Energy	2,278		(3,516		)
Accretion of basis difference	571		575
Investments	12		303
Ending balance	$	104,657	$	101,796

Summarized financial information for Piceance Energy is as follows (in thousands):



	December 31,
	2014		2013
Current assets	$	13,168	$	5,901
Non-current assets	468,379		454,402
Current liabilities	17,103		13,040
Non-current liabilities	107,087		96,738



	Year Ended December 31,
	2014		2013
	100%		100%
Natural gas and oil revenues	$	80,471	$	61,091
Income (loss) from operations	3,768		(6,765		)
Net income (loss)	6,831		(10,546		)

The net income for year ended December 31, 2014 includes $32.8 million and $9.8 million of DD&A expense and unrealized gains on derivative instruments, respectively. The net loss for the year ended December 31, 2013 includes $26.6 million and $1.1 million of DD&A expense and unrealized losses on derivative instruments, respectively.

At December 31, 2014 and 2013, our equity in the underlying net assets of Piceance Energy exceeded the carrying value of our investment by approximately $14.7 million and $15.3 million, respectively. This difference arose due to lack of control and marketability discounts. We attributed this difference to natural gas and oil properties and are amortizing the difference over 15 years based on the estimate of proved reserves at the date Piceance Energy was formed.

Note 4—Acquisitions

We made our acquisitions in furtherance of our growth strategy that focuses on the acquisition of income producing businesses in order to monetize our net operating loss carryforwards.

Mid Pac Plan of Merger

On June 2, 2014, we and our subsidiary entered into an agreement and plan of merger with Koko’oha Investments, Inc., a Hawaii corporation (“Koko’oha”). Koko’oha owns 100% of the outstanding membership interests of Mid Pac Petroleum, LLC, a Delaware limited liability company (“Mid Pac”), which is the exclusive licensee of the “76” brand in the State of Hawaii and the owner/operator of several terminals and retail gasoline stations across Hawaii. Pursuant to the merger agreement, we expect to acquire 100% of Koko’oha and Mid Pac for $107 million, less estimated long-term liabilities, plus estimated merchandise and product inventory, subject to other adjustments as set forth in the merger agreement. Through a series of amendments to the merger agreement with Koko'oha, the date by which we or Koko'oha can terminate the merger agreement for failure to consummate the merger has been extended to March 31, 2015.

We believe we have satisfied the Federal Trade Commission's concerns under the Hart-Scott-Rodino Act and anticipate entering into a consent decree in mid-March. We expect to close the acquisition in April of 2015.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

In connection with and due upon signing the Mid Pac merger agreement, we funded a $10 million deposit against the purchase price, which was funded through proceeds from the Term Loan and is included in Other long-term assets on our consolidated balance sheets. Please read Note 10—Debt for further information. We are obligated to deposit an additional $5 million against the purchase price within three days of the expiration of the waiting period under the HSR Act. If the merger agreement is terminated due to a breach of representations and obligations by us, we forfeit the deposits. If the merger agreement is terminated due to mutual consent, government order or closing does not occur on or before March 31, 2015, the deposits will be refunded to us. If the merger agreement is terminated due to Mid Pac's breach of representations and warranties, the deposits will be returned to us and Mid Pac will be obligated to pay us an additional $5 million if the termination occurs prior to the expiration or early termination of the waiting period under the HSR Act or $7.5 million if it occurs after. In 2014, we incurred $6.4 million in costs related to the Mid Pac acquisition.

Hawaii Independent Energy

On September 25, 2013, one of our subsidiaries completed the acquisition of Tesoro Hawaii which owned and operated a petroleum refinery in Kapolei, Hawaii, certain pipeline assets, floating pipeline mooring equipment, refined products terminals, and retail assets selling fuel products and merchandise on the islands of Oahu, Maui and Hawaii. Following the acquisition, Tesoro Hawaii was renamed Hawaii Independent Energy, LLC (“HIE”). The purchase price was $75 million, paid in cash plus net working capital and inventories at closing plus certain contingent earnout payments of up to $40 million. As a part of the purchase price, we also funded approximately $24.3 million of start-up expenses and for a major overhaul of a co-generation turbine used at the refinery prior to closing. The purchase price was paid with a portion of the net proceeds from the private placement common stock sale (please read Note 13—Stockholders' Equity), amounts received pursuant to the Supply and Exchange Agreements (please read Note 9—Supply and Exchange Agreements) and the ABL Facility (please read Note 10—Debt).

The contingent earnout payments, if any, are to be paid annually following each of the three calendar years beginning January 1, 2014 through the year ending December 31, 2016, in an amount equal to 20% of the consolidated annual gross margin of HIE in excess of $165 million during such calendar years, with an annual cap of $20 million. In the event that the refinery ceases operations or we dispose of any facility used in the acquired business, our obligation to make earnout payments could be modified and/or accelerated. There were no earnout payments due based on the results for the year ended December 31, 2014.

We accounted for the acquisition of HIE as a business combination whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values on the date of acquisition. Goodwill recognized in the transaction was attributable to opportunities expected to arise from combining our operations with HIE’s, and utilization of our net operating loss carryforwards, as well as other intangible assets that do not qualify for separate recognition. In addition, we recorded certain other identifiable intangible assets including trade names and trademarks. These intangible assets will be amortized over their estimated useful lives on a straight line basis, which approximates their consumptive life.

During 2014, we finalized the HIE acquisition purchase price allocation. The primary purchase price allocation adjustments related to the finalization of the post-retirement medical plan, working capital settlements, and allocating value to underground storage tanks installed by Tesoro Corporation in conjunction with the Environmental Agreement. Please read Note 14—Benefit Plans and Note 12—Commitments and Contingencies for additional information. We believe these adjustments did not have a material impact on prior periods.

A summary of the final estimated fair value of the assets acquired and liabilities assumed is as follows (in thousands):



Inventory	$	418,750
Trade accounts receivable	59,553
Prepaid and other current assets	2,497
Property, plant and equipment	59,670
Land	39,800
Goodwill	13,796
Intangible assets	4,596
Accounts payable and other current liabilities	(18,542		)
Contingent consideration liability	(11,980		)
Other non-current liabilities	(7,561		)
Total	$	560,579

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

The acquisition was partially funded from proceeds totaling approximately $378.2 million from the Supply and Exchange Agreements. Please read Note 9—Supply and Exchange Agreements for further information. None of the goodwill or intangible assets are expected to be deductible for income tax reporting purposes. Acquisition costs of approximately $7 million are included in Acquisition and integration expense on our consolidated statement of operations for the year ended December 31, 2013.

The unaudited pro forma financial information for the year ended December 31, 2013 presented below assumes that the HIE acquisitions occurred as of January 1, 2013 (in thousands):



Revenues	$	2,987
Net income	$	(122	)

Revenue and earnings for HIE subsequent to the acquisition are included in the refining and distribution segment and the retail segment in Note 17—Segment Information.

Note 5—Inventories

Inventories at December 31, 2014 and 2013 consist of the following (in thousands):



	December 31, 2014
	Titled Inventory		Supply and Exchange Agreements		Total
Crude oil and feedstocks	$	—	$	62,594	$	62,594
Refined products and blend stock	47,922		118,375		166,297
Warehouse stock and other	14,962		—		14,962
Total	$	62,884	$	180,969	$	243,853



	December 31, 2013
	Titled Inventory		Supply and Exchange Agreements		Total
Crude oil and feedstocks	$	—	$	137,706	$	137,706
Refined products and blend stock	67,532		161,554		229,086
Warehouse stock and other	13,831		—		13,831
Total	$	81,363	$	299,260	$	380,623

The reserves for the lower of cost or market value of inventory was $2.4 million as of December 31, 2014. There was no reserve as of December 31, 2013.

Note 6—Property, Plant and Equipment

Major classes of property, plant and equipment consist of the following (in thousands):



	December 31,
	2014			2013
Land	$	39,800		$	39,800
Buildings and equipment	81,488			65,878
Other	2,035			1,945
Total property, plant and equipment	123,323			107,623
Proved oil and gas properties	1,122			4,949
Less accumulated depreciation, depletion and amortization	(11,510		)	(3,968		)
Property, plant and equipment, net	$	112,935		$	108,604

Note 7—Asset Retirement Obligations

The table below summarizes the changes in our asset retirement obligations (in thousands):



	Year Ended December 31,
	2014			2013
Asset retirement obligation – beginning of period	$	3,172		$	512
Obligation acquired	—			2,601
Accretion expense	239			59
Change in estimate	(831		)	—
Asset retirement obligation – end of period	$	2,580		$	3,172

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Note 8—Intangible Assets

Intangible assets consist of the following (in thousands):



	December 31,
	2014			2013
Intangible assets:
Supplier relationships	$	3,360		$	3,360
Railcar leases	3,249			3,249
Historical shipper status	2,200			2,200
Trade names and trademarks	4,689			4,689
Total intangible assets	$	13,498		$	13,498
Accumulated amortization:
Supplier relationships	$	(516	)	$	(258	)
Railcar leases	(1,301		)	(650		)
Historical shipper status	(2,200		)	(1,100		)
Trade name and trademarks	(1,975		)	(320		)
Total accumulated amortization	$	(5,992	)	$	(2,328	)
Net:
Supplier relationships	$	2,844		$	3,102
Railcar leases	1,948			2,599
Historical shipper status	—			1,100
Trade name and trademarks	2,714			4,369
Total intangible assets, net	$	7,506		$	11,170

Amortization expense was approximately $3.7 million and $2.3 million for the years ended December 31, 2014 and 2013, respectively. Expected amortization expense for each of the next five years and thereafter is as follows (in thousands):



Year Ended	Amount
2015	$	2,518
2016	2,012
2017	908
2018	258
2019	258
Thereafter	1,552
	$	7,506

During the year ended December 31, 2014, the changes in the carrying amount of goodwill were as follows (in thousands):



Balance at beginning of period	$	20,603
HIE acquisition purchase price allocation adjustments ⁽¹⁾	183
Balance at end of period	$	20,786

________________________________________________________

⁽¹⁾ Please read Note 4—Acquisitions for further discussion of these adjustments.

Note 9—Supply and Exchange Agreements

HIE entered into several agreements with Barclays Bank PLC ("Barclays"), referred to collectively as the Supply and Exchange Agreements, on September 25, 2013 in connection with the acquisition of HIE. HIE entered into the Supply and Exchange Agreements for the purpose of managing its working capital and the crude oil and refined product inventory at the refinery. Effective

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

July 31, 2014, HIE supplemented the Supply and Exchange Agreements by entering into the Refined Product Supply Master Confirmation, pursuant to which Barclays may provide refined product supply and intermediation arrangements to HIE.

Pursuant to the Supply and Exchange Agreements, Barclays holds title to all of the crude oil in the tanks at the refinery and holds title to a majority of our refined product inventory in our tanks at the refinery. Barclays also prepaid us for certain inventory held at locations outside of our refinery. We hold title to the inventory during the refining process. Barclays sells the crude oil to us as it is discharged out of the refinery's tanks. We exchange refined product owned by Barclays stored in our tanks for equal volumes of refined product produced by our refinery when we execute third-party sales of refined product. We currently market and sell the refined product independently to third parties. The Supply and Exchange Agreements have an initial term of three years with two one-year renewal options.

We record the inventory owned by Barclays on our behalf because we maintain the risk of loss until the refined products are sold to third parties. Because we do not hold legal title to the crude oil inventory until it enters the refinery, we record a liability in an amount equal to the carrying value of the crude oil inventory.

In accordance with the terms of the Supply and Exchange Agreements, the volume of refined products purchased by Barclays in connection with the acquisition of HIE is known as the “Block Volume”. To the extent we have refined product inventory equal to or in excess of the Block Volume at period-end, we record a liability, valued at the carrying value of the related inventory, for only the Block Volume. To the extent we have refined product inventory less than the Block Volume at period-end, we record a liability for the refined product inventory on hand at its carrying value, plus a liability for the shortfall in volumes valued at current market prices. The liability related to the Supply and Exchange Agreements is included in Obligations under supply and exchange agreements on our consolidated balance sheets.

For the years ended December 31, 2014 and 2013, we incurred approximately $16.5 million and $3.7 million in handling fees related to the Supply and Exchange Agreements, respectively, which is included in Cost of revenues on our consolidated statements of operations. For the years ended December 31, 2014 and 2013, Interest expense and financing costs, net, on our statements of operations includes approximately $4.2 million and $1.1 million of expenses related to the Supply and Exchange Agreements, respectively.

Note 10—Debt

Our debt is as follows (in thousands):



	December 31,
	2014			2013
Term Loan	$	87,360		$	19,480
ABL Facility	—			51,800
Retail Credit Agreement	22,750			26,000
Texadian Uncommitted Credit Agreement	26,500			—
Total debt, net of unamortized debt discount	136,610			97,280
Less current maturities	(29,100		)	(3,250		)
Long-term debt, net of current maturities and unamortized discount	$	107,510		$	94,030

Annual maturities of our long-term debt for the next five years and thereafter are as follows (in thousands):



Year	Amount Due
2015	$	29,100
2016	39,371
2017	2,600
2018	53,189
2019	2,600
Thereafter	9,750
	$	136,610

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Term Loan

During 2012 and 2013, we borrowed $13 million and $17 million, respectively, pursuant to the Delayed Draw Term Loan Credit Agreement ("Loan Agreement"). The lenders under the Loan Agreement included ZCOF Par Petroleum Holdings, L.L.C. and Highbridge International, LLC, who are also our stockholders. In November 2013, we repaid in full and terminated all of our obligations under the Loan Agreement, other than the New Tranche B Loans described below and expensed $6.1 million of financing costs associated with the termination of the Loan Agreement.

On December 28, 2012, we amended the Loan Agreement and borrowed an additional $35 million ("Tranche B Loan"). On June 24, 2013, we refinanced and replaced the Tranche B Loan and borrowed $65 million (“New Tranche B Loans”). We repaid a portion of the New Tranche B Loans with proceeds from a private placement. Please read Note 13—Stockholders' Equity for further information.

The New Tranche B Loans are secured by a lien on substantially all of our assets and our subsidiaries, excluding Texadian, Texadian Energy Canada Limited (“Texadian Canada”), certain of our immaterial subsidiaries, and Hawaii Pacific Energy and its subsidiaries. All our obligations under the New Tranche B Loans are unconditionally guaranteed by the Guarantors.

On May 30, 2014, we entered into a Twelfth Amendment to the Loan Agreement (collectively with the New Tranche B Loans, the "Twelfth Amendment"), pursuant to which we borrowed an additional $13.2 million which was primarily used to fund the deposit due upon signing the merger agreement with Koko'oha. Please read Note 4—Acquisitions.

Borrowings under the Twelfth Amendment bore interest (a) from May 30, 2014 to September 1, 2014 at a rate equal to 12% per annum payable in kind and (b) on and after September 1, 2014 at a rate equal to 14.75% per annum payable, at our election, either in cash or in kind. We also agreed to pay a nonrefundable amendment fee of approximately $506 thousand as well as an original issue discount of approximately $630 thousand. The Twelfth Amendment lenders agreed to waive the exit fee related to the existing New Tranche B Loans of which we had accrued approximately $97 thousand as of the date of the Twelfth Amendment. Except as discussed above, the Twelfth Amendment did not change any other terms or conditions of the New Tranche B Loans.

On July 11, 2014, we and certain subsidiaries entered into a Delayed Draw Term Loan and Bridge Loan Credit Agreement ("Credit Agreement") to provide us with a term loan of up to $50 million ("Term Loan") and a bridge loan of up to $75 million ("Bridge Loan"). The Term Loan amended and restated the Twelfth Amendment, reduced the interest rate, and may be used to fund the additional deposit per the Mid Pac merger agreement, for transaction costs and for working capital and general corporate purposes. The Term Loan matures on July 11, 2018 and bears interest at either 10% per annum if paid in cash or 12% per annum if paid in kind, at our election, and has an original issue discount of 5%. During July 2014, we borrowed $15.5 million to fund transaction costs, provide working capital, and for general corporate purposes.

On July 28, 2014, we entered into a First Amendment to the Credit Agreement pursuant to which we expanded the Term Loan and borrowed an additional $35 million ("Advance"), which resulted in net proceeds to us of approximately $32 million. The Advance was to be repaid upon the receipt of net equity proceeds from the Rights Offering. Please read Note 13—Stockholders' Equity for more information. Except for the repayment terms, all other terms and conditions remained unchanged. We used the proceeds for working capital and general corporate purposes.

On September 3, 2014, we terminated all of the Bridge Loan commitments under the Credit Agreement. On September 10, 2014, we entered into a Second Amendment to the Credit Agreement whereby we extended the repayment date of the Advance to March 31, 2015. All other terms and conditions remained unchanged. We expensed approximately $1.8 million of financing costs associated with the termination of the Bridge Loan. On March 11, 2015, we entered into a Third Amendment to the Credit Agreement whereby we extended the repayment date of the Advance to March 31, 2016; therefore, the Advance has been classified as long-term debt as of December 31, 2014. All other terms and conditions remain unchanged.

Certain lenders to the Credit Agreement are our stockholders. Please read Note 18—Related Party Transactions for more information.

ABL Facility

On September 25, 2013 and in connection with the acquisition of HIE, HIE and its subsidiary (“ABL Borrowers”) and Hawaii Pacific Energy entered into an asset-based senior secured revolving credit facility (“ABL Facility”) of up to $125 million, of which up to $50 million of availability under the ABL Facility may be used for the issuances of letters of credit. The ABL Facility is secured by a lien on substantially all of HIE’s assets. The ABL Borrowers borrowed $15 million on September 25, 2013 under the ABL Facility to fund the acquisition of HIE and to provide working capital to the ABL Borrowers. The proceeds from future amounts borrowed pursuant to the ABL Facility were used for general corporate purposes and to fund the working capital

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

of the ABL Borrowers. As of December 31, 2014, the total capacity of the ABL Facility was $79.5 million and we had $2.4 million of letters of credit outstanding.

Outstanding balances on the ABL Facility bear interest at the base rate specified below (“Base Rate”) plus a margin (based on a sliding scale of 1.00% to 1.50% depending on the borrowing base usage) or the adjusted LIBOR specified below (“Adjusted LIBOR”) plus a margin (based on a sliding scale of 2.00% to 2.50% depending on the borrowing base usage). The margin was 1.25% for Base Rate loans and 2.25% for Adjusted LIBOR loans during 2013. The Base Rate is equal to the highest of (i) the prime lending rate of the ABL Agent, (ii) the Federal Funds Rate plus 0.5% per annum, and (iii) the Adjusted LIBOR for a LIBOR loan denominated in dollars with a one-month interest period commencing on such day plus 1.00%. The effective weighted-average interest rate for 2014 was 2.95%.

The ABL Borrowers agreed to pay commitment fees for the ABL Facility equal to 0.375% if the borrowing base usage is greater than 50%; and 0.500% if the borrowing base usage is less than or equal to 50%. Outstanding letters of credit will be charged a participation fee at a per annum rate equal to the margin applicable to Adjusted LIBOR loans, a facing fee, and customary administrative fees.

All loans and other obligations outstanding under the ABL Facility are payable in full on September 25, 2017.

The ABL Borrowers and Hawaii Pacific Energy are required to comply with various affirmative and negative covenants affecting its business and operations, including compliance with a minimum ratio of consolidated earnings before interest, taxes, depreciation and amortization, as adjusted, to total fixed charges of 1.0 to 1.0.

Retail Credit Agreement

On November 14, 2013, HIE Retail, LLC (“HIE Retail”), our subsidiary, entered into a Credit Agreement (“Retail Credit Agreement”) in the form of a senior secured term loan of up to $30 million (“Retail Term Loan”) and a senior secured revolving line of credit of up to $5 million (“Retail Revolver”). Loans made under the Retail Credit Agreement are secured by a first priority security interest in substantially all of the assets of HIE Retail consisting primarily of 31 distribution outlets, selling fuel products and merchandise on the islands of Oahu, Maui and Hawaii.

The Retail Credit Agreement requires HIE Retail to comply with various financial covenants that are measured on a quarterly basis commencing with the fiscal quarter ending March 31, 2014 and are calculated on a trailing four-quarter basis. Such covenants require HIE Retail to maintain a maximum Leverage Ratio (as defined in the Retail Credit Agreement) of 5.50 to 1.00 in 2014 and ratably adjusts to 4.75:1 in 2018. HIE Retail is also required to maintain a Fixed Charge Coverage Ratio of 1.15:1.00.

Retail Term Loan

Principal on the Retail Term Loan will be repaid in quarterly principal payments over the term through November 14, 2020.

The Retail Term Loan bears interest, at HIE Retail’s election, at a rate equal to (i) 30, 90 and 180 day LIBOR plus the Applicable Margin (as specified below) for LIBOR Loans (as defined in the Retail Credit Agreement), or (ii) the primary interest rate established from time to time by the Agent in the ordinary course of its business plus the Applicable Margin and is payable quarterly. The effective interest rate for 2014 on the outstanding loan was 2.6%.

The Applicable Margin for each fiscal quarter is the applicable rate per annum set forth below, such amount to be determined as of the last day of the immediately preceding fiscal quarter.



Level	Leverage Ratio	Applicable Margin for LIBOR Loans		Applicable Margin for Base Rate Loans
1	<4.00x	2.00	%	—	%
2	4.00x-5.00x	2.25	%	0.25	%
3	>5.00x	2.50	%	0.50	%

Fifty percent of annual Excess Cash Flow (as defined in the Retail Credit Agreement) will be applied to the outstanding principal balance of the Term Loan beginning with Excess Cash Flow for fiscal year 2014 to the extent the leverage ratio is equal to or greater than 4.50:1.00.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Retail Revolver

The Retail Revolver and any letters of credit issued under the Retail Revolver mature on November 14, 2016.

Advances under the Retail Revolver will bear interest, at HIE Retail’s election, at a rate equal to (a) 30, 90 and 180 day LIBOR plus the Revolver Applicable Margin (as defined below) for LIBOR Loans, or (ii) the primary interest rate established from time to time by the Agent in the ordinary course of its business plus the Revolver Applicable Margin.

HIE Retail agreed to pay a fee (“Unused Fee”), based on the leverage ratio on the last date of the immediately preceding quarter as set forth below, based on the unused portion of the Revolver and calculated on the average of the unused amount for the quarter. The Unused Fee is payable quarterly in arrears.

The Retail Revolver Applicable Margin and the Unused Fee, for each quarter is determined, on the last date of the immediately preceding fiscal quarter:



				Revolver		Revolver
				Applicable Margin for		Applicable Margin for
Level	Leverage Ratio	Unused Fee		LIBOR Loans		Base Rate Loans
1	<4.00x	0.250	%	1.75	%	-0.25	%
2	4.00x-5.00x	0.375	%	2.00	%	—	%
3	>5.00x	0.500	%	2.25	%	0.25	%

Commitment fees for Standby Letters of Credit issued under the Revolver are due quarterly in arrears and will be equal to 2.00% per annum on the letter of credit amount payable. As of December 31, 2014, there were no balances or letters of credit outstanding under the Retail Revolver.

Texadian Uncommitted Credit Agreement

On June 12, 2013, Texadian, and its wholly-owned subsidiary Texadian Canada, entered into an Uncommitted Credit Agreement to provide for loans and letters of credit, on an uncommitted and absolutely discretionary basis, in an aggregate amount at any one time outstanding not to exceed $50 million. Loans and letters of credit issued under the Uncommitted Credit Agreement are secured by a security interest in and lien on substantially all of Texadian’s assets, including, but not limited to, cash, accounts receivable, and inventory, a pledge by Texadian of 65% of its ownership interest in Texadian Canada, and a pledge by us of 100% of our ownership interest in Texadian. Texadian agreed to pay certain fees with respect to the loans and letters of credit made available to it under the Uncommitted Credit Agreement, including an up-front fee, an origination fee, a minimum compensation fee, a collateral audit fee, and fees with respect to letters of credit. The Uncommitted Credit Agreement requires Texadian to comply with various affirmative and negative covenants affecting its business, and Texadian must comply with certain financial maintenance covenants, including among other things, covenants regarding the minimum net working capital and minimum tangible net worth of Texadian. The Uncommitted Credit Facility does not permit, at any time, Texadian’s consolidated leverage ratio to be greater than 5.00 to 1.00 or its consolidated gross asset coverage to be equal to or less than zero. As of December 31, 2014, we had $27.6 million of letters of credit outstanding related to this agreement.

On October 10, 2014, the maturity date of the Uncommitted Credit Agreement was extended to May 15, 2015 and the availability was temporarily increased to $85 million. The temporary increase in availability was extended to January 6, 2015 on December 19, 2014.

On February 20, 2015, Texadian, and its wholly-owned subsidiary Texadian Canada, amended and restated the uncommitted credit agreement. The amendment increased the uncommitted loans and letters of credit capacity to $200 million and matures in February 2016.

Cross Default Provisions

Included within each of the our debt agreements are customary cross default provisions that require the repayment of amounts outstanding on demand should an event of default occur and not be cured within the permitted grace period, if any. As of December 31, 2014 we are in compliance with all of our credit agreements.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Note 11—Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Purchase Price Allocation of HIE. The final fair values of the assets acquired and liabilities assumed as a result of the HIE acquisition were estimated as of the date of the acquisition and finalized during the quarter ended September 30, 2014 using valuation techniques described in notes (a) through (g) described below.



				Valuation
	Fair Value			Technique
	(in thousands)
Net working capital	$	462,258		(a)
Property, plant and equipment	59,670			(b)
Land	39,800			(c)
Goodwill	13,796			(d)
Intangible assets	4,596			(e)
Contingent consideration liability	(11,980		)	(f)
Other non-current liabilities	(7,561		)	(g)
Total	$	560,579


(a)	Current assets acquired and liabilities assumed were recorded at their net realizable value.

(b)

The fair value of the property, plant, and equipment was estimated using the cost approach. Under the cost approach, the total replacement cost of the property is determined based on industry sources with adjustments for regional factors. The total cost is then adjusted for depreciation based on the physical age of the assets and external obsolescence. We consider this to be a Level 3 fair value measurement.


(c)	The fair value of the land was estimated using the sales comparison approach. Under this approach, the sales prices of similar properties are adjusted to account for differences in land characteristics. We consider this to be a Level 3 fair value measurement.


(d)	The excess of the purchase price paid over the fair value of the identifiable assets acquired and liabilities assumed is allocated to goodwill.

(e)

The fair value of the trade names and trademarks was estimated using a form of the income approach, the Relief from Royalty Method. Significant inputs used in this model include estimated revenue attributable to the trade names and trademarks and a royalty rate. An increase in the estimated revenue or royalty rate would result in an increase in the value attributable to the trade names and trademarks. We consider this to be a Level 3 fair value measurement.

(f)

The fair value of the liability for contingent consideration was estimated using Monte Carlo simulation. Significant inputs used in the model include estimated future gross margin, annual gross margin volatility and a present value factor. An increase in estimated future gross margin, volatility or the present value factor would result in an increase in the liability. We consider this to be a Level 3 fair value measurement.


(g)	Other non-current assets and liabilities are recorded at their estimated net present value.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Common stock warrants. We estimate the fair value of our outstanding common stock warrants using a Monte Carlo simulation analysis, which is considered to be a Level 3 fair value measurement. Significant inputs used in the Monte Carlo simulation analysis include:



	December 31,
	2014	2013
Stock price	$16.25	$22.30
Weighted average exercise price	$0.10	$0.10
Term (years)	7.67	8.67
Risk-free rate	2.01%	2.78%
Expected volatility	50.2%	52.9%

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

The expected volatility is based on the 10-year historical volatilities of comparable public companies. Based on the Monte Carlo simulation analysis, the estimated fair value of the common stock warrants was $16.17 and $21.64 per share as of December 31, 2014 and 2013, respectively. Since the common stock warrants were in the money upon issuance, we do not believe that changes in the inputs to the Monte Carlo simulation analysis will have a significant impact to the value of the common stock warrants other than changes in the value of our common stock. Increases in the value of our common stock will increase the value of the common stock warrants. Likewise, a decrease in the value of our common stock will result in a decrease in the value of the common stock warrants.

Debt prepayment derivative. A previous loan agreement contained a contingent prepayment feature that we accounted for as a derivative. At June 30, 2013, we reduced the carrying value of the debt prepayment derivative to zero because we did not believe there was any probability of us repaying the loan prior to maturity. This was considered a Level 3 fair value measurement. In November 2013, we repaid in full and terminated all of our obligations, including any repayment premiums, under this loan agreement thus extinguishing the liability.

Derivative instruments. From time to time, we enter into certain exchange traded oil contracts that do not qualify for or for which we do not elect the normal purchase or normal sale exception. Changes in the fair value of these contracts are recorded in earnings. The fair value of our commodity derivatives is measured using the closing market price at the end of the reporting period obtained from the New York Mercantile Exchange and from third-party broker quotes and pricing providers.

Contingent consideration. The cash consideration for our acquisition of HIE may be increased pursuant to an earn out provision. The liability is remeasured at the end of each reporting period using a Monte Carlo simulation analysis. Significant inputs used in the valuation model include estimated future gross margin, annual gross margin volatility and a present value factor. We consider this to be a Level 3 fair value measurement.

Financial Statement Impact

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013 and their placement within our consolidated balance sheet consist of the following (in thousands):



		December 31,
	Balance Sheet Location	2014			2013
		Asset (Liability)
Common stock warrants	Common stock warrants	$	(12,123	)	$	(17,336	)
Contingent consideration liability	Contingent consideration liability	(9,131		)	(11,980		)
Exchange-traded futures	Prepaid and other current assets	1,015			—

The following table summarizes the pre-tax gain (loss) recognized in our consolidated statement of operations resulting from changes in fair value of derivative instruments not designated as hedges charged directly to earnings (in thousands):



		Year Ended December 31,
	Statement of Operations Classification	2014		2013
Common stock warrants	Change in value of common stock warrants	$	4,433	$	(10,159	)
Contingent consideration liability	Change in value of contingent consideration	2,849		—
Debt repayment derivative	Interest expense and financing costs, net	—		45
Derivatives - exchange traded futures	Cost of revenues	8,228		104
Commodities - physical forward contracts	Cost of revenues	—		306

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013 and their level within the fair value hierarchy is as follows (in thousands):



	December 31, 2014
	Fair Value			Level 1		Level 2		Level 3
Common stock warrants	$	(12,123	)	$	—	$	—	$	(12,123	)
Contingent consideration liability	(9,131		)	—		—		(9,131		)
Derivatives - exchange traded futures	1,015			1,015		—		—



	December 31, 2013
	Fair Value			Level 1		Level 2		Level 3
Common stock warrants	$	(17,336	)	$	—	$	—	$	(17,336	)
Contingent consideration liability	(11,980		)	—		—		(11,980		)

A roll forward of Level 3 derivative instruments measured at fair value on a recurring basis is as follows (in thousands):



	Year Ended December 31,
	2014			2013
Balance, at beginning of period	$	(29,316	)	$	(10,945	)
Settlements	780			3,723
Acquired	—			(11,980		)
Total unrealized income (loss) included in earnings	7,282			(10,114		)
Balance, at end of period	$	(21,254	)	$	(29,316	)

The carrying value and fair value of long-term debt and other financial instruments as of December 31, 2014 and 2013 is as follows (in thousands):



	December 31, 2014
	Carrying Value		Fair Value ⁽¹⁾
Term Loan	$	87,360	$	87,068
ABL Facility ⁽²⁾	—		—
HIE Retail Credit Agreement ⁽²⁾	22,750		22,750
Texadian Uncommitted Credit Agreement	26,500		26,500
Common stock warrants	12,123		12,123
Contingent consideration liability	9,131		9,131



	December 31, 2013
	Carrying Value		Fair Value ⁽¹⁾
Term Loan	$	19,480	18,800
ABL Facility ⁽²⁾	51,800		51,800
HIE Retail Credit Agreement ⁽²⁾	26,000		26,000
Common stock warrants	17,336		17,336
Contingent consideration liability	11,980		11,980

_________________________________________________________

⁽¹⁾ The fair values of these instruments are considered Level 3 measurements in the fair value hierarchy.

⁽²⁾ Fair value approximates carrying value due to the floating rate interest.

We estimate our long-term debt’s fair value using a discounted cash flow analysis and an estimate of the current yield of 14.11% and 15.28% as of December 31, 2014 and 2013, respectively, by reference to market interest rates for term debt of comparable companies.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

The fair value of all non-derivative financial instruments included in current assets, including cash and cash equivalents, restricted cash and trade accounts receivable, current liabilities, and accounts payable approximate their carrying value due to their short term nature.

Note 12—Commitments and Contingencies

Environmental Matters

Like other petroleum refiners and exploration and production companies, 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.

Regulation of Greenhouse Gases. The United States Environmental Protection Agency (“EPA”) has begun regulating greenhouse gases ("GHG") under the Clean Air Act Amendments of 1990 (“Clean Air Act”). 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.

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). Those rules are pending final approval by the Government of Hawaii. The refinery’s capacity to reduce fuel use and GHG emissions is limited. However, the state’s pending regulation allows, and the refinery should be able to demonstrate, that additional reductions are not cost-effective or necessary in light of the state’s current GHG inventory and future year projections. The pending 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.

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 United States 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 billion gallons by 2022. In the near term, the RFS2 will be satisfied primarily with fuel ethanol blended into gasoline. 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.

In October 2010, the EPA issued a partial waiver decision under the Clean Air Act 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. In January 2011, the EPA issued a second waiver for the use of E15 in vehicles model years 2001-2006. 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. Since April 2006, the State of Hawaii has required that a minimum of 9.2% ethanol be blended into at least 85% of the gasoline pool, but the regulation also limited the amount of ethanol to no more than 10%. Consequently, unless either the state or federal regulations are revised, qualified Renewable Identification Numbers (“RINS”) will be required to fulfill the federal mandate for renewable fuels.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

In March 2014, the EPA published a final Tier 3 gasoline standard that lowers the allowable sulfur level in gasoline to 10 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. Along with credit and trading options, potential capital upgrades for the refinery are being evaluated.

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. 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.

Environmental Agreement

On September 25, 2013 (“Closing Date”), Hawaii Pacific Energy (a wholly-owned subsidiary of Par created for purposes of the HIE acquisition), Tesoro and HIE entered into an Environmental Agreement (“Environmental Agreement”), which allocated responsibility for known and contingent environmental liabilities related to the acquisition of HIE, including the Consent Decree as described below.

Consent Decree. Tesoro is currently negotiating a consent decree with the EPA and the United States Department of Justice 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 the Hawaii refinery. It is anticipated that the Consent Decree will be finalized sometime during the first half of 2015 and will require certain capital improvements to our refinery to reduce emissions of air pollutants.

Tank Replacements. Tesoro replaced, at its expense, the existing underground storage tanks at six retail locations. The tank replacements were completed at five of the stations during 2014. The sixth location was completed during the first quarter of 2015.

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 Environmental 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 HIE prior to the Closing Date, certain groundwater remediation work, the replacement of underground storage tanks located at certain retail sites, fines or penalties imposed on HIE by the Consent Decree related to acts or omissions of Tesoro prior to the Closing Date and to claims and losses related to the Pearl City Superfund Site.

Recovery Trusts

We emerged from the reorganization of Delta Petroleum on August 31, 2012 ("Emergence Date") when the plan of reorganization ("Plan") was consummated. On the Emergence Date, we formed the Delta Petroleum General Recovery Trust (“General Trust”). The General Trust was formed to pursue certain litigation against third parties, including preference actions, fraudulent transfer and conveyance actions, rights of setoff and other claims, or causes of action under the U.S. Bankruptcy Code, and other claims and potential claims that the Debtors hold against third parties.

We are the beneficiary of the General Trust, subject to the terms of the respective 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,

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

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.

As of December 31, 2014 and 2013, 27 and 28 claims totaling approximately $26.5 million and $40.2 million remain to be resolved by the trustee for the General Trust and we have reserved approximately $1.1 million and $3.8 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at period end, respectively. During the year ended December 31, 2014, the trustee for the General Trust settled one claim from U.S. Bank of $3.7 million. In October 2014, we issued 146 thousand shares of common stock to settle this claim. During the year ended December 31, 2013, the trustee for the General Trust settled 59 claims of $26.9 million for approximately $5.4 million in cash and 209 thousand shares of common stock.

A summary of claims is as follows (in thousands, except number of filed claims):



	For The Year Ended December 31, 2014
							Remaining Filed
	Settled Claims						Claims
				Consideration
	Count	Amount		Cash		Stock	Count	Amount
U.S. Government Claims	—	$	—	$	—	—	2	$	22,364
Other Various Claims	1	3,702		—		146	25	4,158
Total	1	$	3,702	$	—	146	27	$	26,522



	For The Year Ended December 31, 2013
							Remaining Filed
	Settled Claims						Claims
				Consideration
	Count	Amount		Cash		Stock	Count	Amount
U.S. Government Claims	1	$	—	$	—	—	2	$	22,364
Former Employee Claims	19	12,695		340		162	—	—
Macquarie Capital (USA) Inc.	1	8,672		2,500		—	—	—
Swann and Buzzard Creek Royalty Trust	1	3,200		2,000		—	—	—
Other Various Claims ⁽¹⁾	37	2,339		543		47	26	17,860
Total	59	$	26,906	$	5,383	209	28	$	40,224

_____________________________


⁽¹⁾	Includes reserve for contingent/unliquidated claims in the amount of $10 million.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Capital Leases

Within our retail segment, we have capital lease obligations related primarily to the leases of five retail stations with initial terms of 17 years and generally five years remaining on the current term, with four 5-year renewal options. Minimum annual lease payments including interest, for capital leases are as follows (in thousands):



2015	$	382
2016	382
2017	382
2018	420
2019	420
Thereafter	—
Total minimum lease payments	1,986
Less amount representing interest	460
Total minimum rental payments	$	1,526

Operating Leases

Within our refining and distribution segment and our retail segment, we have various cancellable and noncancellable operating leases related to land, vehicles, office and retail facilities, and other facilities used in the storage, transportation, and sale of crude oil and refined products. The majority of the future lease payments relate to retail stations and facilities used in the storage, transportation and sale of crude oil and refined products. We have operating leases for most of our retail stations with primary terms of up to 50 years with an average of 12 years remaining, and generally containing renewal options and escalation clauses. Leases for facilities used in the storage, transportation and sale of crude oil and refined products have various expiration dates extending to 2027.

In addition, with our commodity marketing and logistics segment, we have various agreements to lease storage facilities, primarily along the Mississippi River, railcars, inland river tank barges and towboats, and other equipment. These leasing agreements have been classified as operating leases for financial reporting purposes and the related rental fees are charged to expense over the lease term as they become payable. The leases generally range in duration of five years or less and contain lease renewal options at fair value. Our railcar leases contain an empty mileage indemnification provision whereby if the empty mileage exceeds the loaded mileage, we are charged for the empty mileage at the rate established by the tariff of the railroad on which the empty miles accrued.

Minimum annual lease payments extending to 2044 for operating leases to which we are legally obligated and having initial or remaining non-cancellable lease terms in excess of one year are as follows (in thousands):



2015	$	28,944
2016	13,263
2017	11,224
2018	9,902
2019	7,954
Thereafter	18,194
Total minimum rental payments	$	89,481

Rent expense for the year ended December 31, 2014 and 2013 was approximately $30.2 million and $6.2 million, respectively.

Major Customers

For the year ended December 31, 2014 and 2013, no individual customer accounted for more than 10% of our consolidated revenue.

Other

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

On April 22, 2013, Texadian entered into a terminaling and storage agreement whereby the operator would provide Texadian with storage facilities, access to a marine terminal and pipelines and railcar offloading services. The initial term of the agreement was for a period of four years and Texadian's minimum commitment during the initial term was approximately $28 million. Effective February 1, 2015, Texadian and the counterparty (i) terminated this terminaling and storage agreement and (ii) entered into a new agreement with an initial term of one year.

Note 13—Stockholders' Equity

Common Stock

Our certificate of incorporation contains restrictions on the transfer of certain of our securities in order to preserve the net operating loss carryovers, capital loss carryovers, general business credit carryovers, alternative minimum tax credit carryovers and foreign tax credit carryovers, as well as any “net unrealized built-in loss” within the meaning of Section 382 of the Internal Revenue Service Code, of us or any direct or indirect subsidiary thereof. These restrictions include provisions regarding approval by our Board of Directors of transfers of Common Stock by holders of five percent or more of the outstanding Common Stock. Our debt agreements restrict the payment of dividends.

We amended our certificate of incorporation to implement a one-for-ten (1:10) reverse stock split of our issued and outstanding common stock, par value $0.01 per share, effective on January 29, 2014 for trading purposes. All references in the financial statements to the number of shares of common stock or warrants, price per share and weighted average number of common stock shares outstanding prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis, unless otherwise noted.

On September 25, 2013, we completed a private placement transaction and issued approximately 14.4 million shares of common stock resulting in net proceeds of approximately $199.2 million. We incurred approximately $830 thousand of offering costs which are included as a reduction of Additional paid-in capital on our consolidated balance sheet.

Registration Rights Agreements

In connection with our emergence from bankruptcy on August 31, 2012, we entered into a registration rights agreement (“Registration Rights Agreement”) providing the stockholders party thereto (“Stockholders”) with certain registration rights.

The Registration Rights Agreement states that at any time after the consummation of a qualified public offering, any Stockholder or group of Stockholders that, together with its or their affiliates, holds more than fifteen percent of the Registrable Shares (as defined in the Registration Rights Agreement), will have the right to require us to file with the SEC a registration statement for a public offering of all or part of its Registrable Shares (each a “Demand Registration”), by delivery of written notice to the company (each, a “Demand Request”).

Within 90 days after receiving the Demand Request, we must file with the SEC the registration statement with respect to the Demand Registration, subject to certain limitations as set forth in the Registration Rights Agreement. We are required to use commercially reasonable efforts to cause the registration statement to be declared effective as soon as practicable after such filing.

In addition, subject to certain exceptions, if we propose to register any class of common stock for sale to the public, we are required, subject to certain conditions, to include all Registrable Shares with respect to which we have received written requests for inclusion.

In connection with the closing of a private placement, we entered into an additional registration rights agreement with the purchasers of the shares. Under this registration rights agreement, we agreed to file a registration statement relating to the shares of common stock with the SEC within 60 days after the closing date of the sale which would be declared effective within 180 days of the closing date of the sale. We also agreed to use commercially reasonable efforts to keep the registration statement effective until the earliest to occur of (i) the disposition of all registrable securities, (ii) the availability under Rule 144 of the Securities Act of 1933, as amended, for each holder of registrable securities to immediately freely resell such registrable securities without volume restrictions or (iii) the third anniversary of the effective date of the registration statement.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

This registration rights agreement also provides the right for a holder or group of holders of more than $50 million of registrable securities to demand that we conduct an underwritten public offering of the registrable securities. However, the demanding holders are limited to a total of three such underwritten offerings, with no more than one demand request for an underwritten offering made in any 365 day period. Additionally, this registration rights agreement contains customary indemnification rights and obligations for both us and the holders of registrable securities.

If this registration statement (i) is not filed with the SEC on or prior to the applicable deadline (ii) is not declared effective by the SEC prior to the applicable deadline, or (iii) does not remain effective for the applicable effectiveness period described above then from the that date until cured, we must pay, as liquidated damages and not as a penalty, an amount in cash equal to 0.25% of the purchaser’s allocated purchase price per calendar month, not to exceed 0.75% of the allocated purchase price.

The registration rights granted in each rights agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions such as suspension periods and, if a registration is for an underwritten offering, limitations on the number of shares to be included in the underwritten offering imposed by the managing underwriter.

Incentive Plan

On December 20, 2012, our Board of Directors (“Board”) approved the Par Petroleum Corporation 2012 Long Term Incentive Plan (“Incentive Plan”). Under the Incentive Plan, the Board, or a committee of the Board, may issue up to 1.6 million shares of our common stock, or incentive stock options, nonstatutory stock options or restricted stock to our employee or directors, or other individuals providing services to us. In general, the terms of any award issue will be determined by the committee upon grant.

These awards primarily vest ratably over five years. For the year ended December 31, 2014, the following activity occurred under our Incentive Plan (in thousands, except per share amounts), which includes the restricted common stock issued under the Stock Purchase Plan discussed below:



	Shares		Weighted- Average Grant Date Fair Value
Non vested balance, beginning of period	524		$	16.29
Granted	239		18.49
Vested	(196	)	15.04
Forfeited	—
Non vested balance, end of period	567		$	17.65
Available for grant	852

For the years ended December 31, 2014 and 2013, we recognized compensation costs of approximately $4.8 million and $1.2 million, respectively, related to restricted stock awards in general and administrative expenses within our consolidated statements of operations related to restricted stock awards under our Incentive Plan. As of December 31, 2014 and 2013, there was approximately $7.5 million and $8.1 million, of total unrecognized compensation costs related to restricted stock awards, which are expected to be recognized on a straight-line basis over a weighted average period of 3.75 years and 4.37 years, respectively.

On September 8, 2014, we entered into a separation agreement with our former chief operating officer and he retired. Pursuant to the separation agreement, we agreed to vest approximately 110 thousand shares of unvested restricted common stock issued under the Incentive Plan as follows (i) approximately 27 thousand shares vested on December 31, 2014 and (ii) approximately 83 thousand shares will vest upon the earlier of the closing or termination of the Mid Pac acquisition. Please read Note 4—Acquisitions for more information. Such shares would have been forfeited under the original terms of the restricted stock grant. As a result of this modification, we recorded $1.7 million of compensation costs during the year ended December 31, 2014, which is included in annual activity disclosed above.

Stock Purchase Plan

On June 12, 2014, the Board adopted a Stock Purchase Plan (“SPP”) plan. The SPP is limited to the Company’s qualifying executive officers and directors. The SPP provides that each participant may during the twelve month period beginning with the date of adoption of the SPP, purchase, in a single transaction, up to $1 million of shares of our common stock at a per share purchase price equal to the closing price of the common stock on the date of purchase. The sale or transfer of the Shares by such participant would be limited for the earlier of (i) two years from the date of purchase or (ii) the termination of the participant’s service with

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

the Company or its affiliates for any reason. Additionally, the SPP provides that each purchasing participant will be granted a number of shares of restricted common stock under the Incentive Plan equal to 20% of the shares purchased with 50% of the restricted common stock vesting on each of the two annual anniversaries of the date of grant, pursuant to the terms and conditions of the award of restricted stock. Each purchasing participant will also be granted a nonstatutory stock option with a 5-year term to purchase a number of shares of common stock under the Incentive Plan (with an exercise price equal to the fair market value as defined in the Incentive Plan on the date of grant) equal to certain specified percentages of the shares purchased based on a Black Scholes model with 50% of the options vesting on each of the two annual anniversaries of the date of grant. Such percentages are as follows: 50% for a non-employee chairman of the Board, 35% for non-employee members of the Board and 50%-70% for executive officers.

The fair value of each option is estimated on the grant date using the Black-Scholes option-pricing model. The estimated weighted-average grant-date fair value per share of options granted during 2014 was $5.91. Unrecognized compensation cost related to non-vested stock options as of December 31, 2014 totaled $2.2 million and is expected to be recognized over a weighted-average period of 2.0 years.

For the year ended December 31, 2014, the following stock option activity occurred (options in thousands):



	Number of Options	Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term in Years	Aggregate Intrinsic Value
Outstanding, beginning of year	—	$	—	—	$	—
Issued	401	16.18
Exercised	—	—
Forfeited / canceled	—	—
Outstanding, end of year	401	$	16.18	5.5	$	—
Vested, end of year	—				$	—
Exercisable, end of year	—				$	—

The expected life of options granted is based on the term of the option. Expected volatilities are based on the historical volatility of our stock. Expected dividend yield is based on annualized dividends at the grant date. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. Our weighted-average assumptions used to measure stock options granted during 2014 are presented below:



	2014
Expected life from date of grant (years)	5
Expected volatility	35	%
Expected dividend yield	—	%
Risk-free interest rate	1.76	%

Note 14—Benefit Plans

Defined Contribution Plan

We maintain several defined contribution plans for our employees. Eligible employees can enter the plans either immediately or after one year of service, depending on the plan. The plans permit employee contributions up to the IRS limits per year. For some plans, we contribute 3% of the employee’s eligible compensation to the plan regardless of the employee’s contribution. On all plans, we match a portion of all the employee’s contributions up to 6% depending on the plan. In addition, we have a money purchase pension plan for certain eligible employees. Under this plan, we make contributions to employee directed investment accounts ranging from 5.5% to 8.5% of eligible compensation depending on the employee’s age. For the years ended December 31, 2014 and 2013, we made contributions to the plans totaling approximately $1.2 million and $502 thousand, respectively.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Other Post-retirement Benefits - Medical

Our refining and distribution segment and our retail segment sponsor a post-retirement medical plan to provide health care coverage continuation from the date of retirement to age 65 for qualifying employees. Employees hired before 2006 are generally eligible to participate in the plan after five years of service and reaching the age of 55 and will pay 20% of the monthly insurance premium. Employees hired after 2006 are generally eligible to participate in the plan after five years of service and reaching the age of 55 and are required to pay 100% of the monthly insurance premium; however, after 10 years of service, they are only required to pay 50% of the monthly insurance premium.

The post-retirement medical plan resulted from the HIE acquisition and qualifying employees were credited with their prior service under Tesoro which resulted in the recognition of a liability for the projected benefit obligation. However, employees who were vested under the Tesoro post-retirement medical plan on the date of acquisition remain a liability under the Tesoro plan. As such, we did not assume any of these employees’ liability under the plan.

The changes in the benefit obligation of our post-retirement medical plan as of and for the years ended December 31, 2014, and 2013 were as follows (in thousands):



	2014		2013
Benefit obligation at the beginning of year	$	4,505	$	—
Acquisition of HIE	—		4,385
Service cost	260		69
Interest cost	194		52
Plan amendments	48		—
Actuarial loss (gain)	407		(1		)
Projected benefit obligation at end of year	$	5,414	$	4,505

The post-retirement medical plan is an unfunded plan and therefor had no plan assets as of and for the years ended December 31, 2014, and 2013.

Estimated future benefit payments, which reflect expected future services, that we expect to pay for our post-retirement medical plan are as follows (in thousands):



2015	$	14
2016	37
2017	74
2018	123
2019	195
2020–2024	2,359

The components of the net periodic benefit cost for the years ended December 31, 2014, and 2013 were as follows (in thousands):



	2014		2013
Service cost	$	260	$	69
Interest cost	194		52
Amortization of prior service cost	9		—
Net periodic benefit cost	$	463	$	121

The pre-tax amounts in accumulated other comprehensive loss as of December 31, 2014 and 2013 that have not yet been recognized as components of net periodic costs were as follows (in thousands):

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013



	2014		2013
Prior service cost (credit)	$	39	$	—
Net actuarial loss (gain)	407		(1		)
Total	$	446	$	(1	)

The weighted-average discount rates used to determine the benefit obligations as of December 31, 2014 and 2013 were 3.50% and 4.50% respectively. The discount rates were selected by comparing the expected plan cash flows to the December 31, 2014 and 2013 Citigroup Pension Discount Curve. The weighted average discount rate used to determine net periodic benefit costs for the years ended December 31, 2014 and 2013 was 4.5%.

Note 15—Loss Per Share

Basic loss per share is computed by dividing net loss by the sum of the weighted average number of common shares outstanding and the weighted average number of shares issuable under the common stock warrants, representing 749,148 shares and 790,683 shares as of December 31, 2014 and 2013, respectively. The common stock warrants are included in the calculation of basic loss per share because they are issuable for minimal consideration. Non-vested restricted stock is excluded from the basic weighted-average common stock outstanding computation as these shares are not considered earned until vested. The following table sets forth the computation of basic and diluted earnings per share (in thousands, except per share amounts):



	Year Ended December 31,
	2014			2013
Net loss attributable to common stockholders	$	(47,041	)	$	(79,173	)
Basic weighted-average common stock outstanding	32,739			19,740
Add dilutive effects of common stock equivalents ⁽¹⁾	—			—
Diluted weighted-average common stock outstanding	32,739			19,740

Basic loss per common share ⁽¹⁾	$	(1.44	)	$	(4.01	)
Diluted loss per common share⁽¹⁾	$	(1.44	)	$	(4.01	)

________________________________________________________


⁽¹⁾	Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. We have utilized the basic shares outstanding to calculate both basic and diluted loss per share.

As of December 31, 2014 and 2013, our weighted average potentially dilutive securities excluded from the calculation of diluted shares outstanding consisted of 567 thousand and 524 thousand shares of non-vested restricted stock and 401 thousand and no shares of stock options, respectively.

Note 16—Income Taxes

We have approximately $1.4 billion in net operating loss carryforwards ("NOL carryforwards"); however, we currently have a full valuation allowance against this tax asset. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment. Based upon the level of historical taxable income, significant book losses during the current and prior periods, and projections for future results of operations over the periods in which the deferred tax assets are deductible, among other factors, management concluded that we did not meet the “more likely than not” requirement of ASC 740 in order to recognize deferred tax assets and a valuation allowance has been recorded for the full amount of our net deferred tax assets at December 31, 2014 and 2013.

In connection with our emergence from bankruptcy on August 31, 2012, we experienced an ownership change as defined under Section 382 of the Code. Section 382 generally places a limit on the amount of NOL carryforwards and other tax attributes arising before an ownership change that may be used to offset taxable income after an ownership change. We believe that we will qualify for an exception to the general limitation rules. This exception under Code Section 382(l)(5) provides for substantially less restrictive limitations on our NOL carryforwards; however, the NOL carryforwards are eliminated should another ownership change occur within three years. Our amended and restated certificate of incorporation places restrictions upon the ability of the

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

certain equity interest holders to transfer their ownership interest us. These restrictions are designed to provide us with the maximum assurance that another ownership change does not occur that could adversely impact our NOL carryforwards.

During the years ended December 31, 2014 and 2013, no adjustments were recognized for uncertain tax benefits.

Our net taxable income must be apportioned to various states based upon the income tax laws of the states in which we derive our revenue. Our NOL carry forwards will not always be available to offset taxable income apportioned to the various states. The states from which Texadian’s revenues and HIE’s revenues are derived are not the same states in which our NOLs were incurred; therefore we expect to incur state tax liabilities on the net income of Texadian’s and HIE’s operations.

During 2015 and thereafter, we will continue to assess the realizability of our deferred tax assets based on consideration of actual and projected operating results and tax planning strategies. Should actual operating results improve, the amount of the deferred tax asset considered more likely than not to be realizable could be increased.

Income tax expense (benefit) consisted of the following:



	Year Ended December 31,
	2014			2013
Current:
U.S.—Federal	$	—		$	—
U.S.—State	(264		)	(179		)
Foreign	(80		)	—
Deferred:
U.S.—Federal	(14		)	(14		)
U.S.—State	(177		)	193
Foreign	80			—
Total	$	(455	)	$	—

Income tax expense was different from the amounts computed by applying U.S. Federal income tax rate of 35% to pretax income as a result of the following:



	Year Ended December 31,
	2014		2013
Federal statutory rate	35.0	%	35.0	%
State income taxes, net of federal benefit	1.3	%	(0.1	)%
Change in valuation allowance	(38.8	)%	(23.1	)%
Permanent Items	3.6	%	(3.7	)%
Provision to return adjustments	(0.1	)%	(8.1	)%
Actual income tax rate	1.0	%	—	%

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Deferred tax assets (liabilities) are comprised of the following (in thousands):



	December 31,
	2014			2013
Deferred tax assets:
Net operating loss	$	528,782		$	535,959
State deferred tax assets	7,885			8,418
Capital loss carry forwards	26,141			26,141
Property and equipment	34,312			34,683
Investment in Piceance Energy	31,334			32,138
Other	6,112			2,510
Total deferred tax assets	634,566			639,849
Valuation allowance	(631,599		)	(637,464		)
Net deferred tax assets	$	2,967		$	2,385
Deferred tax liabilities:
Property and equipment	$	—		$	5
Texadian Energy intangibles	1,677			2,380
Other	1,272			—
State liabilities	57			216
Total deferred tax liabilities	$	3,006		$	2,601
Total deferred tax liability, net	$	(39	)	$	(216	)

We have net operating loss carryovers as of December 31, 2014 of $1.4 billion for federal income tax purposes. If not utilized, the tax net operating loss carryforwards will expire during 2027 through 2033. Our capital loss carryovers as of December 31, 2014 are $74.7 million. If not utilized, these carryovers will expire during 2015 and 2016. We also have Alternative Minimum Tax Credit Carryovers of $800 thousand. These credits do not expire; however, we must first generate regular taxable income before they can be used.

Note 17—Segment Information

Effective in the first quarter of 2015, we changed our reportable segments to separate our retail operations from our prior refining, distribution and marketing segment due to a change in senior leadership, organizational structure and to reflect how we currently make financial decisions and allocate resources. After the realignment, our structure consists of the following four business segments: (i) Refining and Distribution, (ii) Retail, (iii) Natural Gas and Oil Production, and (iv) Commodity Marketing and Logistics. Corporate and Other includes trust litigation and settlements and other administrative costs. We have recast the segment information for the years ended December 31, 2014 and 2013 to conform to the current presentation. Summarized financial information concerning reportable segments consists of the following (in thousands):

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013



For the year ended December 31, 2014	Refining and Distribution			Retail		Natural Gas and Oil Production			Commodity Marketing and Logistics			Corporate and Other			Total
Segment revenues	$	2,816,667		$	231,673	$	5,984		$	189,160		$	—		$	3,243,484
Intersegment elimination	(135,459		)	—		—			—			—			(135,459		)
Revenues	2,681,208			231,673		5,984			189,160			—			3,108,025
Costs of revenue	2,566,811			187,150		—			183,511						2,937,472
Operating expense, excluding DD&A	115,785			25,115		—			—			—			140,900
Lease operating expenses	—			—		5,673			—			—			5,673
Depreciation, depletion, and amortization	7,889			2,353		2,376			2,018			261			14,897
Loss on sale of assets, net	—			—		624			—			—			624
General and administrative expense	12,746			2,858		37			4,310			14,353			34,304
Acquisition and integration costs	4,576			—		—			—			7,111			11,687
Operating (loss) income	(26,599		)	14,197		(2,726		)	(679		)	(21,725		)	(37,532		)
Interest expense and financing costs, net															(19,783		)
Other income (expense), net															(312		)
Change in value of common stock warrants															4,433
Change in value of contingent consideration															2,849
Equity earnings from Piceance Energy, LLC															2,849
Loss before income taxes															(47,496		)
Income tax expense															455
Net loss															$	(47,041	)

Total assets	$	418,211		$	42,389	$	105,615		$	87,695		$	87,097		$	741,007
Goodwill	$	—		$	13,796	$	—		$	6,990		$	—		$	20,786
Capital expenditures	$	14,314		$	479	$	12		$	300		$	1,523		$	16,628

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013



For the year ended December 31, 2013	Refining and Distribution			Retail		Natural Gas and Oil Production			Commodity Marketing and Logistics		Corporate and Other			Total
Segment revenues	$	755,406		$	48,913	$	7,739		$	100,149	$	—		$	912,207
Intersegment elimination	(26,193		)	—		—			—		—			(26,193		)
Revenues	729,213			48,913		7,739			100,149		—			886,014
Costs of revenue	734,122			39,461		—			83,483					857,066
Operating expense, excluding DD&A	21,428			5,823		—			—		—			27,251
Lease operating expense	—			—		5,676			—		—			5,676
Depreciation, depletion, and amortization	1,690			577		1,706			2,009		—			5,982
Loss on sale of assets, net	—			—		(50		)	—		—			(50		)
Trust litigation and settlements	—			—		—			—		6,206			6,206
General and administrative expense	2,605			291		130			5,206		13,262			21,494
Acquisition and integration costs	—			—		—			—		9,794			9,794
Operating (loss) income	(30,632		)	2,761		277			9,451		(29,262		)	(47,405		)
Interest expense and financing costs, net														(19,426		)
Other income (expense), net														758
Change in value of common stock warrants														(10,159		)
Equity loss from Piceance Energy, LLC														(2,941		)
Loss before income taxes														(79,173		)
Income tax expense														—
Net loss														$	(79,173	)

Total assets	$	605,769		$	36,071	$	109,316		$	52,048	$	10,009		$	813,213
Goodwill	$	—		$	13,613	$	—		$	6,990	$	—		$	20,603
Capital expenditures	$	6,753		$	—	$	471		$	—	$	544		$	7,768

Note 18—Related Party Transactions

Term Loan

Certain of our stockholders, or affiliates of our stockholders, are the lenders under our Term Loan. In previous years, they received common stock warrants exercisable for shares of common stock in connection with the origination of the Term Loan. Please read Note 10—Debt for further information.

Equity Group Investments ("EGI") and Whitebox - Service Agreements

On September 17, 2013, we entered into letter agreements (“Services Agreements”) with Equity Group Investments (“EGI”), an affiliate of Zell Credit Opportunities Fund, LP ("ZCOF"), and Whitebox Advisors, LLC, ("Whitebox") each of which own 10% or more of our common stock directly or through affiliates. Pursuant to the Services Agreements, EGI and Whitebox agreed to provide us with ongoing strategic, advisory and consulting services that may include (i) advice on financing structures and our relationship with lenders and bankers, (ii) advice regarding public and private offerings of debt and equity securities, (iii) advice regarding asset dispositions, acquisitions or other asset management strategies, (iv) advice regarding potential business acquisitions, dispositions or combinations involving us or our affiliates, or (v) such other advice directly related or ancillary to the above strategic, advisory and consulting services as may be reasonably requested by us.

EGI and Whitebox will not receive a fee for the provision of the strategic, advisory or consulting services set forth in the Services Agreements, but may be periodically reimbursed by us, upon request, for (i) travel and out of pocket expenses, provided that in the event that such expenses exceed $50 thousand in the aggregate with respect to any single proposed matter, EGI or Whitebox, as applicable, will obtain our consent prior to incurring additional costs, and (ii) provided that we provide prior consent to their engagement with respect to any particular proposed matter, all reasonable fees and disbursements of counsel, accountants and other professionals incurred in connection with EGI’s or Whitebox’s, as applicable, services under the Services Agreements. In consideration of the services provided by EGI and Whitebox under the Services Agreements, we agreed to indemnify each of them for certain losses incurred by them relating to or arising out of the Services Agreements or the services provided thereunder.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

The Services Agreements have a term of one year and will be automatically extended for successive one-year periods unless terminated by either party at least 60 days prior to any extension date. There were no significant costs incurred related to these agreements during the year ended December 31, 2014 or 2013.

Note 19—Disclosures About Capitalized Costs, Costs Incurred (Unaudited)

Capitalized costs related to oil and gas activities are as follows (in thousands):



	December 31,
	2014			2013
Company:
Unproved properties	$	—		$	—
Proved properties	1,122			4,949
	1,122			4,949
Accumulated depreciation and depletion	(824		)	(1,868		)
	$	298		$	3,081
Company’s Share of Piceance Energy:
Unproved properties	$	15,872		$	15,763
Proved properties	183,937			168,378
	199,809			184,141
Accumulated depreciation and depletion	(49,666		)	(38,452		)
	$	150,143		$	145,689

Costs incurred in oil and gas activities including costs associated with assets retirement obligations, are as follows (in thousands):



	Year Ended December 31,
	2014		2013
Company:
Development costs incurred on proved undeveloped reserves	$	—	$	—
Development costs—other	102		142
Total	$	102	$	142
Company’s Share of Piceance Energy:
Unproved properties acquisition costs	$	—	$	—
Development costs—other	15,599		6,380
Total	$	15,599	$	6,380

For the years ended December 31, 2014 and 2013, neither we or Piceance incurred exploratory well costs so no amounts were capitalized or expensed during these respective periods. Accordingly, there were no suspended exploratory well costs at 2014 and 2013 that were being evaluated.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

A summary of the results of operations for oil and gas producing activities, excluding general and administrative costs, is as follows:



	Year Ended December 31,
	2014			2013
Company:
Revenue:
Oil and gas revenues	$	5,984		$	7,739
Expenses:
Production costs	5,673			5,696
Depletion and amortization	2,376			1,593
Exploration	—			—
Abandoned and impaired properties	—			—
Results of operations of oil and gas producing activities	$	(2,065	)	$	450
Company’s share of Piceance Energy:
Revenue:
Oil and gas revenues	$	26,829		$	20,364
Expenses:
Production costs	11,140			9,885
Depletion and amortization	10,921			8,855
Results of operations of oil and gas producing activities	$	4,768		$	1,624
Total Company and Piceance Energy income from operations of oil and gas producing activities	$	2,703		$	2,074

Note 20—Information Regarding Proved Oil and Gas Reserves (Unaudited)

There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.

Estimates of our oil and natural gas reserves and present values as of December 31, 2014 and 2013, were prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

A summary of changes in estimated quantities of proved reserves for the years ended December 31, 2014 and 2013 is as follows:



	Gas		Oil		NGLS		Total
	(MMcf)		(MBbl)		(MBbl)		(MMcfe) ⁽¹⁾
Company:
Estimated Proved Reserves: Balance at January 1, 2013	446		286		—		2,163
Revisions of quantity estimate	460		16		—		557
Extensions and discoveries	9		3		—		25
Production	(253	)	(69	)	—		(667	)
Estimated Proved Reserves: Balance at December 31, 2013⁽²⁾	662		236		—		2,078
Revisions of quantity estimate	65		(67	)	21		(211	)
Extensions and discoveries	8		1		—		14
Production	(134	)	(93	)	(4	)	(716	)
Estimated Proved Reserves: Balance at December 31, 2014⁽³⁾	601		77		17		1,165
Company’s Share of Piceance Energy:
Estimated Proved Reserves: Balance at January 1, 2013	122,650		831		6,345		165,700
Revisions of quantity estimate	72,436		174		2,818		90,387
Extensions and discoveries	3,599		(374	)	(1,334	)	(6,643	)
Production	(12,088	)	(47	)	(428	)	(14,935	)
Estimated Proved Reserves: Balance at December 31, 2013⁽²⁾	186,597		584		7,401		234,509
Revisions of quantity estimate	8,876		34		(1,689	)	(1,054	)
Extensions and discoveries	21,108		128		489		24,808
Production	(4,831	)	(18	)	(125	)	(5,689	)
Estimated Proved Reserves: Balance at December 31, 2014⁽³⁾	211,750		728		6,076		252,574
Total Estimated Proved Reserves: Balance at December 31, 2014	212,351		805		6,093		253,739

__________________________________________________


⁽¹⁾	MMcfe is based on a ratio of 6 Mcf to 1 barrel.

⁽²⁾

During 2013, the Company's estimated proved reserves, inclusive of the Company's share of Piceance Energy's estimated proved reserves, increased by 68,724 MMcfe or approximately 41%. Revisions of quantity estimates related to our share of Piceance Energy's estimated proved reserves resulted in an increase of 90,387 MMcfe from the beginning of year reserves. These revisions are primarily associated with wells that became economic during 2013.

⁽³⁾

During 2014, the Company's estimated proved reserves, inclusive of the Company's share of Piceance Energy's estimated proved reserves, increased by 17,152 MMcfe or approximately 7%. Extensions and discoveries related to our share of Piceance Energy's estimated proved reserves resulted in an increase of 24,808 MMcfe from the beginning of year reserves. These extensions and discoveries are primarily associated with successful completions by Piceance Energy.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013



	Gas	Oil	NGLS	Total
	(MMcf)	(MBbl)	(MBbl)	(MMcfe) ⁽¹⁾
Proved developed reserves
December 31, 2013	662	236	—	2,078
December 31, 2013-Company Share of Piceance Energy	45,072	165	1,627	55,829
Total December 31, 2013	45,734	401	1,627	57,907
Proved undeveloped reserves
December 31, 2013	—	—	—	—
December 31, 2013-Company Share of Piceance Energy	141,525	419	5,774	178,680
Total December 31, 2013	141,525	419	5,774	178,680
Proved developed reserves
December 31, 2014	601	77	17	1,165
December 31, 2014-Company Share of Piceance Energy	48,855	195	1,226	57,381
Total December 31, 2014	49,456	272	1,243	58,546
Proved undeveloped reserves
December 31, 2014	—	—	—	—
December 31, 2014-Company Share of Piceance Energy	162,895	533	4,850	195,193
Total December 31, 2014	162,895	533	4,850	195,193

__________________________________________________


⁽¹⁾	MMcfe is based on a ratio of 6 Mcf to 1 barrel.



	CIG per MMbtu		WTI per Bbl
Base pricing, before adjustments for contractual differentials (Company and Piceance): ⁽¹⁾
December 31, 2013	$	3.53	$	96.91
December 31, 2014	$	4.36	$	94.99

__________________________________________________


⁽¹⁾	Proved reserves are required to be calculated based on the 12-month, first day of the month historical average price in accordance with SEC rules. The prices shown above are base index prices to which adjustments are made for contractual deducts and other factors.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

Future net cash flows presented below are computed using applicable prices (as summarized above) and costs and are net of all overriding royalty revenue interests.



	December 31,
	2014			2013
	(in thousands)
Company:
Future net cash flows	$	10,452		$	26,861
Future costs:
Production	7,760			21,999
Development and abandonment	37			319
Income taxes ⁽¹⁾	—			—
Future net cash flows	2,655			4,543
10% discount factor	(889		)	(1,006		)
Standardized measure of discounted future net cash flows	$	1,766		$	3,537
Company’s Share of Piceance Energy:
Future net cash flows	$	1,268,704		$	984,205
Future costs:
Production	539,796			430,506
Development and abandonment	236,027			234,905
Income taxes ⁽¹⁾	—			—
Future net cash flows	492,881			318,794
10% discount factor	(322,282		)	(229,469		)
Standardized measure of discounted future net cash flows	$	170,599		$	89,325
Total Company and Company share of equity investee in the standardized measure of discounted future net revenues	$	172,365		$	92,862

________________________________________________

⁽¹⁾ No income tax provision is included in the standardized measure calculation shown above as we do not project to be taxable or pay cash income taxes based on its available tax assets and additional tax assets generated in the development of its reserves because the tax basis of its oil and gas properties and NOL carryforwards exceeds the amount of discounted future net earnings.

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2014 and 2013

The principal sources of changes in the standardized measure of discounted net cash flows for the years ended December 31, 2014 and 2013 are as follows (in thousands):



	Year Ended December 31, 2014
	Company			Company Share of Piceance Energy			Total
Beginning of the year
Beginning of the period	$	3,537		$	89,325		$	92,862
Sales of oil and gas production during the period, net of production costs	(1,288		)	(3,763		)	(5,051		)
Net change in prices and production costs	(31		)	35,837			35,806
Changes in estimated future development costs	118			(6,292		)	(6,174		)
Extensions, discoveries and improved recovery	85			4,914			4,999
Revisions of previous quantity estimates, estimated timing of development and other	(1,111		)	27,632			26,521
Previously estimated development and abandonment costs incurred during the period	102			14,013			14,115
Other	—			—			—
Accretion of discount	354			8,933			9,287
End of period	$	1,766		$	170,599		$	172,365



	Year Ended December 31, 2013
	Company			Company Share of Piceance Energy			Total
Beginning of the year
Beginning of the period	$	8,010		$	71,959		$	79,969
Sales of oil and gas production during the period, net of production costs	(2,044		)	(10,478		)	(12,522		)
Net change in prices and production costs	(3,833		)	(2,588		)	(6,421		)
Changes in estimated future development costs	—			8,831			8,831
Extensions, discoveries and improved recovery	147			15,471			15,618
Revisions of previous quantity estimates, estimated timing of development and other	395			(4,948		)	(4,553		)
Previously estimated development and abandonment costs incurred during the period	—			3,142			3,142
Other	61			740			801
Accretion of discount	801			7,196			7,997
End of period	$	3,537		$	89,325		$	92,862

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