10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 0-16203

PAR PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	84-1060803
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

800 Gessner Road, Suite 875
Houston, Texas	77024
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (281) 899-4800

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

Securities registered under to Section 12(g) of the Act: Common stock, par value $0.01 per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

Indicate by check mark whether the registrant has filed all document and reports required to be filed by Sections 12, 13 or 15 (d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.    Yes  x    No  ¨

The aggregate market value of voting common equity held by non-affiliates of the registrant was approximately $55,000,000 based on the closing price of the common stock on the OTCQB Marketplace of $16.30 per share as of June 28, 2013. As of March 26, 2014, 30,159,039 shares of registrant’s Common Stock, $0.01 par value, were issued and outstanding.

Documents Incorporated By Reference

Certain information required to be disclosed in Part III of this report is incorporated by reference from an amendment to this report which will be filed not later than 120 days after the end of the fiscal year covered by this report.

TABLE OF CONTENTS

	PAGE
PART I
Item 1. BUSINESS	1
Item 1A. RISK FACTORS	15
Item 1B. UNRESOLVED STAFF COMMENTS	22
Item 2. PROPERTIES	23
Item 3. LEGAL PROCEEDINGS	26
Item 4. MINE SAFETY DISCLOSURES	27
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	27
Item 6. SELECTED FINANCIAL DATA	28
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	28
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	43
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	43
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	43
Item 9A. CONTROLS AND PROCEDURES	43
Item 9B. OTHER INFORMATION	44
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	44
Item 11. EXECUTIVE COMPENSATION	44
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	44
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	44
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES	44
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES	45

 PART I

Item  1.BUSINESS

General

We are a diversified energy company based in Houston, Texas (OTCQB:PARR). 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. Currently, we operate in three segments: an integrated refining, distribution and marketing business in Hawaii, non-operated interests in natural gas and oil assets and a commodity marketing and logistics business focused on moving Canadian crude oil to refining hubs in the U.S. The terms “Par,” “Successor,” “we,” “our,” and “us” refer to Par Petroleum Corporation and its consolidated subsidiaries unless the context suggests otherwise. The term “Predecessor” refers to Delta for the periods prior to the reorganization.

In September  2013, we acquired Hawaii Independent Energy, LLC (“HIE”) (formerly known as Tesoro Hawaii, LLC; “Tesoro Hawaii”) from Tesoro Corporation (“Tesoro”) for approximately $75 million in cash, plus net working capital and inventory at closing, plus certain contingent earn out payments of up to approximately $40 million (the “HIE Acquisition”).  As 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.  In connection with the acquisition of HIE, we entered into a Transition Services Agreement with Tesoro to provide certain transition services to us including finance/accounting, tax, retail operations, information technology, environmental, health and safety, marine, human resources and other services for a period of time.

Our integrated refining, distribution and marketing business operates the refinery in Kapolei, Hawaii, with approximately 2.4 million barrels of crude oil and feedstock storage and 2.5 million barrels of refined products storage. The refinery produces ultra-low sulfur diesel, gasoline, jet fuel, marine fuel and other associated refined products primarily for consumption in Hawaii. Our refinery logistics assets include five refined products terminals, 27 miles of pipelines, a single point mooring and other associated logistics assets. In addition, we distribute products through 31 retail outlets located across the islands of Oahu, Maui and Hawaii.

Our most significant natural gas and oil asset is a 33.34% interest in a joint venture called Piceance Energy, LLC (“Piceance Energy”) (see “ - Bankruptcy and Plan of Reorganization”). The remaining ownership interest in Piceance Energy is held by Laramie Energy II, LLC (“Laramie”), which manages the day-to-day operations of the joint venture. Piceance Energy was formed and capitalized in August 2012 when we and Laramie contributed natural gas and oil assets, surface real estate, and other related assets located in the Piceance Basin geological province of Colorado to the joint venture pursuant to a contribution agreement.

In December 2012, we acquired Texadian Energy, Inc. (“Texadian”) (formerly known as SEACOR Energy, Inc.) for an adjusted purchase price of approximately $14 million in cash, plus approximately $3 million in working capital. Our focus in this segment is the sourcing, marketing, transportation and distribution of commodities, primarily crude oil. Our logistics assets consist of historical pipeline shipping status, a leased rail car fleet, and leased inland marine equipment, 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, the Gulf Coast and the East Coast regions of the United States.

Effective for trading purposes on January 29, 2014, our common stock underwent a one-for-ten (1:10) reverse stock split. All references in this Annual Report to the number of shares of common stock or warrants to purchase common stock, price per share and weighted average number of common stock outstanding prior to the 1:10 reverse stock split have been adjusted to reflect this reverse stock split on a retroactive basis, unless otherwise noted. No adjustments have been made to the share or per share amounts of our predecessor, Delta.

Our principal executive office is located at 800 Gessner Road, Suite 875, Houston, Texas 77024, and our telephone number is (281) 899-4800.

Refining, Distribution and Marketing

Our refinery is located in Kapolei on Oahu on approximately 130 fee-owned acres about 20 miles west of Honolulu and is rated at 94,000 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.

Set forth below is a simplified block flow diagram of the major processing units at our refinery:

1

We distribute our products through three main channels: wholesale, retail and bulk. We also occasionally export refined products. Our retail distribution business serves 31 Tesoro branded retail sites: one card lock facility, three sites operated by third parties and 27 company operated convenience stores. Bulk distribution serves primarily utilities, airports, military bases, marine vessels and industrial end-users. Our wholesale distribution efforts focus on jobbers and other non-end users.

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. We own and operate a pipeline transporting products from our refinery to delivery locations that include our Sand Island terminal, which we operate, Honolulu International Airport, interconnections to navy and air force fuel facilities, and another terminal in Honolulu Harbor.  Four proprietary pipelines connect our refinery to Kalaeloa Barbers Point Harbor, provide interconnections to the other local refinery, local utility and another terminal on the west side of Oahu.The pipelines are bidirectional allowing for both delivery and receipt of products.Kalaeloa Barbers Point Harbor, approximately three miles away, is where refined products are loaded on barges for transporting to the neighboring islands or on vessels for export.We can also receive products there.We operate a proprietary trucking business at our refinery and terminals to transport refined products to our customers. We operate terminals on Maui and on the Island of Hawaii and operate an aviation fuel terminal on Kauai.

2

The following map depicts the location of our refining, distribution and marketing assets throughout Hawaii:

 

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 agreement has an initial term of four years from September 25, 2013 and has two one-year extension options. A royalty of approximately $26,000 is payable each month, waived for the first three years.

Crack spreads, or the difference between the price we pay for crude oil and other feedstocks and the prices we receive for refined products, tend to be seasonably lower in the fourth quarter compared to the balance of the year.

In November 2013, HIE contributed substantially all of its retail assets to HIE Retail, LLC, a wholly-owned indirect subsidiary of Par. 

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. Since our emergence from bankruptcy, 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, 2013, the estimated proved reserves of Piceance Energy are the following (unaudited):

	Natural
	Gas	Oil	NGLs	Total
	(MMcf)	(MBbls)	(MBbls)	(MMcfe) (1)
Proved Developed	135,189	496	4,882	167,457
Proved Undeveloped	424,543	1,256	17,321	536,005
Total Proved	559,732	1,752	22,203	703,462

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

3

The following table presents the estimated proved reserves that we own directly and indirectly through Piceance Energy as of December 31, 2013 (unaudited):

	Natural
	Gas	Oil	NGLs	Total
	(MMcf)	(MBbl)	(MBbLs)	(MMcfe) (1)
Company:
Proved Developed	662	236	—	2,078
Proved Undeveloped	—	—	—	—
Total Proved Reserves - Company	662	236	—	2,078
Company Share of Piceance Energy:
Proved Developed	45,072	165	1,627	55,829
Proved Undeveloped	141,525	419	5,774	178,680
Total Proved Reserves- Piceance Energy	186,597	584	7,401	234,509
Total Combined Proved Reserves	187,259	820	7,401	236,587

The following table presents the estimated proved developed producing, proved developed non-producing and proved undeveloped reserves that we own directly and indirectly through Piceance Energy as of December 31, 2013 (unaudited):

	Proved		Proved
	Developed		Developed		Proved
	Producing		Non-producing		Undeveloped		Total(2)
	(M$)		(M$)		(M$)		(M$)
Company:
Estimated pre-tax future net cash flows	$	4,543	$	—	$	—	$	4,543
Standardized measure of discounted future net cash flows	$	3,537	$	—	$	—	$	3,537
Company Share of Piceance Energy:
Estimated pre-tax future net cash flows	$	73,541	$	29,365	$	215,888	$	318,794
Standardized measure of discounted future net cash flows	$	43,812	$	10,372	$	35,141	$	89,325
Total
Estimated pre-tax future net cash flows	$	78,084	$	29,365	$	215,888	$	323,337
Standardized measure of discounted future net cash flows	$	47,349	$	10,372	$	35,141	$	92,862

(1)

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

(2)

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 $89.70 per barrel of oil, $32.05 per barrel of natural gas liquids and $3.74 per Mcf of natural gas.

Reconciliation of PV-10 to Standardized Measure. PV-10 is the estimated present value of the future net revenues from 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.

The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2013 (in thousands):

			Company Share
			of Piceance
	Company		Energy		Total
PV-10	$	3,537	$	89,325	$	92,862
Present value of future income taxes discounted at 10% (1)		—		—		—
Standardized measure of discounted future net cash flows	$	3,537	$	89,325	$	92,862

(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 see Note 15 – Income Taxes.

For more on our natural gas and oil operations, see “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.

4

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 over 175 rail cars. 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, distribution and marketing 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 (see “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 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 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. As 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.

Bankruptcy and Plan of Reorganization

Background and Plan Approval

In December 2011 and January 2012, Delta and its subsidiaries filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). Delta and its subsidiaries included in the bankruptcy petitions are collectively referred to as the “Debtors.”

In March 2012, the Debtors obtained approval from the Bankruptcy Court to proceed with Laramie as the sponsor of a plan of reorganization (the “Plan”). In June 2012, Delta entered into a contribution agreement (the “Contribution Agreement”) with a new joint venture formed by Delta and Laramie, Piceance Energy, to effect the transactions contemplated by the Plan.

The Plan was declared effective on August 31, 2012 (the “Emergence Date”). On the Emergence Date, Delta consummated the transactions contemplated by the Contribution Agreement and each of Delta and Laramie contributed their respective assets in the Piceance Basin to Piceance Energy. Piceance Energy is owned 66.66% by Laramie and 33.34% by us.

On the Emergence Date, Delta also amended and restated its certificate of incorporation and bylaws and changed its name to “Par Petroleum Corporation.” The amended and restated certificate of incorporation contains restrictions that render void certain transfers of the company’s stock that involve a holder of five percent or more of its shares. The purpose of this provision is to preserve certain of our tax attributes, including net operating loss carryforwards that we believe may have value. 

Piceance Energy

Contemporaneously with the consummation of the Contribution Agreement, Par Piceance Energy Equity LLC, a wholly-owned subsidiary of the company (“Par Piceance Energy Equity”), entered into a Limited Liability company Agreement with Laramie that governs the operations of Piceance Energy (the “Piceance Energy LLC Agreement”). Pursuant to the Piceance Energy LLC Agreement, Piceance Energy is managed by Laramie, which controls its day-to-day operations, subject to the supervision of a six-person board, four of which were appointed by Laramie and two of which were appointed by Par Piceance Energy Equity. Certain major decisions require the unanimous consent of the board. The Piceance Energy LLC Agreement provides that the sole manager, Laramie, may make a written capital call up to an aggregate combined total capital contribution of $60 million if approved by the board. Our maximum share of such capital call would currently be $20 million. If any member does not fund its share of the capital call, its interest may be reduced or diluted to the extent of the shortfall. The Piceance Energy LLC Agreement also contains certain restrictions on transfers by the members of their units. One such restriction provides that in the event one member elects to sell or transfer a majority of its units, the other member may elect to participate in such sale. The Piceance Energy LLC Agreement also provides that under certain circumstances, a member desiring to transfer all, but not less than all, of its units may require the other member to participate in such transfer.

5

General Recovery Trust and Wapiti Trust

On the Emergence Date, two trusts were formed; the Wapiti Recovery Trust (the “Wapiti Trust”) and the Delta Petroleum General Recovery Trust (the “General Trust,” and together with the Wapiti Trust, the “Recovery Trusts”). The Recovery Trusts were 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 Recovery Trusts were funded with $1.0 million each pursuant to the Plan.

In September 2012, the Wapiti Trust settled all causes of action against Wapiti Oil & Gas Energy, LLC (“Wapiti Oil & Gas”). Wapiti Oil & Gas made a one-time cash payment in the amount of $1.5 million to the Wapiti Trust, as consideration for the release of claims against it. These proceeds were then distributed to us, along with funds remaining from the initial funding of the Wapiti Trust of approximately $1.0 million. The Wapiti Trust was liquidated in 2013.

The General Trust is pursuing all bankruptcy causes of action not otherwise vested in the Wapiti Trust, 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 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.

Through December 31, 2013, the Recovery Trusts have 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.

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, 2012, the Recovery Trustee settled 25 claims with an aggregate face amount of $6.6 million for $259 thousand in cash and 20,275 shares of common stock.  Pursuant to the Plan, during the year ended December 31, 2013, the Recovery Trustee settled an additional 59 claims with an aggregate face amount of $26.9 million for approximately $5.4 million in cash and 208,460 shares of common stock.

As of December 31, 2013, it is estimated that a total of 28 claims totaling approximately $40.2 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, 2013, we have reserved approximately $3.8 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at period end (see “Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commitments and Contingencies – Bankruptcy Matters”).

6

Environmental Regulations

General

Our activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, regulations and rules regulating the release of materials in the environment or otherwise relating to the protection of human health, safety and the environment will not have a material effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot predict what effect additional regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

Periodically, we receive communications from various federal, state, and local governmental authorities asserting violations of environmental laws and/or regulations.  These governmental entities may also propose or assess fines or require corrective actions for these asserted violations.  We intend to respond in a timely manner to all such communications and to take appropriate corrective action.  We do not anticipate that any such matters currently asserted will have a material impact on our financial condition, results of operations, or cash flows.

Refining activities. Like other petroleum refiners, our operations are subject to extensive and periodically changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities.  Many of these regulations are becoming increasingly stringent, and the cost of compliance can be expected to increase over time.  Our policy is to accrue environmental and clean-up related costs of a non-capital nature when it is probable that a liability has been incurred and the amount can be reasonably estimated.  Such estimates may be subject to revision in the future as regulations and other conditions change.

Natural gas and oil production. Our activities with respect to exploration and production of natural gas and oil, including the drilling of wells and the operation and construction of pipelines, plants and other facilities for extracting, transporting, processing, treating or storing natural gas, crude oil, and other petroleum products, are subject to stringent environmental regulation by state and federal authorities, including the United States Environmental Protection Agency (“US 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 oil and gas 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 US EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA.The US EPA has now begun regulating greenhouse gases under the CAA.  New construction or material expansions that meet certain greenhouse gas emissions thresholds will likely require that, among other things, a greenhouse gas 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 greenhouse gas 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 US EPA is currently developing refinery-specific greenhouse gas regulations and performance standards that are expected to impose, on new and modified operations, greenhouse gas 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 US 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.

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In 2007, the State of Hawaii passed Act 234, which required that greenhouse gas emissions be rolled back on a state wide 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 greenhouse gas emissions were reported to the US 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 greenhouse gas 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 greenhouse gas 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.

Regulation of GHG emissions is new and highly controversial, and 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.

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 US 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 US 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 US 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 US 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 US 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 nation-wide 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.

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 in the refining segment of our business. 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.

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 US 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 precipitate on production equipment or area soils during oil and natural gas extraction or processing. NORM wastes are regulated under the RCRA framework, although such wastes may qualify for the oil and gas hazardous waste exclusion. Primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM-contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards.

Our natural gas and oil properties have been operated by third parties that controlled the treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to refineries and to natural gas and oil wastes and properties have gradually become stricter over time. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators) or to perform remedial operations to prevent future contamination.

Superfund

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release or threatened release of a “hazardous substance” into the environment. These persons include the current owner and operator of a site, any former owner or operator who operated the site at the time of a release, transporters and persons that disposed or arranged for the disposal of hazardous substances at a site. CERCLA also authorizes the US 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.

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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 (the “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 $75 million, and lesser limits for some vessels depending upon their size. The regulations promulgated under OPA impose proof of financial responsibility requirements that can be satisfied through insurance, guarantee, indemnity, surety bond, letter of credit, qualification as a self-insurer, or a combination thereof. The amount of financial responsibility required depends upon a variety of factors including the type of facility or vessel, its size, storage capacity, 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 (the “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 (the “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.

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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 US EPA has commissioned a study to identify potential risks associated with hydraulic fracturing. The US EPA published a progress report on this study in December 2012 and a draft report is expected to be delivered for peer review and public comment 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 state-wide regulatory programs. A state ballot initiative has also be 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 US 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 US EPA as described in more detail below. US 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 US EPA has finalized new rules to limit air emissions from many hydraulically fractured natural gas wells. The new regulations will require use of equipment to capture gases that come from such wells during the drilling process (so-called green completions) after January 1, 2015. Other new requirements, many effective in 2013, involve tighter standards for emissions associated with gas production, storage and transport. While these new requirements are expected to increase the cost of natural gas production, we do not anticipate that we will be 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.

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Environmental Agreement

On September 25, 2013 (the “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 (the “Environmental Agreement”), which allocated responsibility for known and contingent environmental liabilities related to the acquisition of HIE as follows:

Consent Decree.Tesoro is currently negotiating a consent decree with the US 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 (the “Consent Decree”), including our refinery.  It is anticipated that the Consent Decree will be finalized sometime during 2014 and will require certain capital improvements to our refinery to reduce emissions of air pollutants.

It is not possible at this time to estimate the cost of compliance with the final decree. 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 has agreed, at its expense, to replace the existing underground storage tanks at certain retail locations.

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 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 (the “OCSLA”), which was administered by the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”) and, after October 1, 2011, its successors, the BOEM and the Bureau of Safety and Environmental Enforcement (the “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.

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On August 8, 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. This comprehensive act contains many provisions that will encourage oil and gas 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” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas.

In 2007, the FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. The monitoring and reporting required by these rules have increased our administrative costs. We do not anticipate that we will be affected any differently than other producers of natural gas.

Our sales of crude oil, condensate and natural gas liquids are not currently regulated, and are subject to applicable contract provisions made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to the FERC’s jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.

The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC’s regulation of gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate, and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation by the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, pipeline rates are subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline.

Federal Leases

We maintain operations located on federal oil and natural gas leases, which are administered by the BOEMRE, BOEM or BSEE, pursuant to the OCSLA. The BOEMRE and its successors, the BOEM and the BSEE, regulate offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on offshore California, and removal of facilities.

On January 19, 2011, the U.S. Department of the Interior announced that it would divide offshore oil and gas responsibilities among three separate agencies, with the reorganization to be completed in 2011. The Department of the Interior first created the Office of Natural Resources Revenue to manage revenue collection on October 1, 2010. Effective October 1, 2011, the remaining functions of BOEMRE were split into two federal bureaus, the BOEM, which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, NEPA analysis and environmental studies, and the BSEE, which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, after October 1, 2011, we are required to interact with two newly formed federal bureaus to obtain approval of our exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays as the functions of the former BOEMRE are fully divested and implemented in the two federal bureaus. At this time, we cannot predict the impact that this reorganization, or future regulations of enforcement actions taken by the new agencies, may have on our operations. Our federal oil and natural gas leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require compliance with detailed BOEMRE regulations and orders that are subject to interpretation and change by the BOEM or BSEE. The BOEMRE has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines, and the BOEM or the BSEE may in the future amend these regulations.

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To cover the various obligations of lessees on the Outer Continental Shelf (the “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 (the “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 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 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 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 event, the rates that we could charge for gas, the transportation of gas, 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 gas wells and production facilities near occupied buildings. The COGCC increased its setback distance to a uniform 500 feet statewide setback from occupied buildings and a uniform 1,000 feet statewide setback from high occupancy building units. The new setback rules also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface owners and the owners of occupied building units. The new rules also require operators to provide advance notice to surface owners within 500 feet of proposed operations, the owners of occupied buildings within 1,000 feet of proposed operations, and local governments prior to the filing of an Application for Permit to Drill or Oil and Gas Location Assessment. The new rules include expanded outreach and communication efforts by an operator.

In January 2013, the COGCC also approved two rules that require operators to sample groundwater for hydrocarbons and other indicator compounds both before and after drilling. The new statewide rule requires sampling of up to four water wells within a half mile radius of a new oil and gas well before drilling, two samples between six and 12 months after completion, and two more samples between five and six years after completion. The revised rule for the Greater Wattenberg Area (“GWA”) requires operators to sample one water well per quarter governmental section before drilling and between six to 12 months after completion.

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Legislative Proposals

In the past, Congress has been very active in the area of natural gas regulation. New legislative proposals in Congress and the various state legislatures, if enacted, could significantly affect the natural gas and oil industry. At the present time it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on our operations.

Impact of Dodd-Frank Act Derivatives Regulation

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which was passed by Congress and signed into law in July 2010, contains significant derivatives regulation, including requirements that certain transactions be cleared on exchanges and that collateral (commonly referred to as “margin”) be posted for such transactions. The Dodd-Frank Act provides for a potential exception from these clearing and collateral requirements for commercial end-users and it includes a number of defined terms used in determining how this exception applies to particular derivative transactions and the parties to those transactions. As required by the Dodd-Frank Act, the Commodities Futures and Trading Commission (“CFTC”) has promulgated numerous rules to define these terms. The CFTC’s final rules establishing position limits for certain derivatives transactions were vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on certain core futures and equivalent swap contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new positions limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

It is possible that the CFTC, in conjunction with prudential regulators, may mandate that financial counterparties entering into swap transactions with end-users must do so with credit support agreements in place, which could result in negotiated credit thresholds above which an end-user must post collateral. If this should occur, we intend to manage our credit relationships to minimize collateral requirements.

The CFTC’s final rules may also have an impact on our hedging counterparties. For example, our bank counterparties may be required to post collateral and assume compliance burdens resulting in additional costs. We expect that much of the increased costs could be passed on to us, thereby decreasing the relative effectiveness of our hedges and our profitability. To the extent we incur increased costs or are required to post collateral 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, 2013, we employed 536 people, 117 of which are nonexempt employees at the refinery who are represented by the United Steelworkers. Our current collective bargaining agreement is set to expire in January 2015. We consider our relations with our employees to be satisfactory.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K may constitute “forward-looking” statements as defined in Section 27A of the Securities Act, 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 the 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.

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The forward-looking statements contained in this Annual Report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this Annual Report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Item 1A. - Risk Factors” “Item 5. - Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this Annual Report. All forward-looking statements speak only as of the date they are made. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Item 1A. RISK FACTORS

Our businesses involve a high degree of risk. You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this Annual Report. If any of the following risks, or any risk described elsewhere in this Annual Report actually occurs, our business, business prospects, financial condition, results of operations or cash flows could be materially adversely affected. In any such case, the trading price of our common stock could decline. The risks described below are not the only ones facing our company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us.

The HIE Acquisition involves risks associated with acquisitions and integrating acquired businesses and the intended benefits of the HIE Acquisition may not be realized.

The HIE Acquisition involves risks associated with acquisitions and integrating acquired businesses into existing operations, including:

• our senior management’s attention, and a significant amount of our resources, may be diverted from the management of daily operations of our other businesses to the integration of HIE;

• we could incur significant unknown and contingent liabilities for which we have limited or no contractual remedies or insurance coverage;

• the businesses acquired in the HIE Acquisition may not perform as well as we anticipate; and

• unexpected costs, delays and challenges may arise in integrating HIE into our existing operations.

If we fail to integrate HIE into our existing businesses, or if we fail to realize the full benefits we anticipate from the HIE Acquisition, our business, results of operations and financial condition could be adversely affected.

The volatility of crude oil prices and refined product prices may have a material adverse effect on our cash flow and results of operations.

Earnings and cash flows from our refining, distribution and marketing segment depend on a number of factors, including to a large extent the cost of crude oil and other refinery feedstocks which has fluctuated significantly in recent years. While prices for refined products are influenced by the price of crude oil, the constantly changing margin between the price we pay for crude oil and other refinery feedstocks and the prices we receive for refined products (the “crack spread”) also fluctuates significantly from time to time. These prices depend on numerous factors beyond our control, including the global supply and demand for crude oil, gasoline and other refined products, which are subject to, among other things:

• changes in the global economy and the level of foreign and domestic production of crude oil and refined products;

• availability of crude oil and refined products and the infrastructure to transport crude oil and refined products;

• local factors, including market conditions, the level of operations of other refineries in our markets, and the volume of refined products imported;

• threatened or actual terrorist incidents, acts of war, and other global political conditions;

• government regulations; and

• weather conditions, hurricanes or other natural disasters.

In addition, we purchase our refinery feedstocks before manufacturing and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the manufactured refined products from these feedstocks could have a significant impact on our financial results. We also purchase refined products manufactured by others for sale to our customers. Price level changes during the periods between purchasing and selling these refined products could also have a material adverse effect on our business, financial condition and results of operations.

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We cannot be certain that our net operating loss tax carryforwards will continue to be available to offset our tax liability.

As of December 31, 2013, we estimated that we had approximately $1.3 billion of net operating loss tax carryforwards (“NOLs”). In order to utilize the NOLs, we must generate taxable income that can offset such carryforwards. The availability of NOLs to offset taxable income would be substantially reduced or eliminated if we were to undergo an “ownership change” within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”). We will be treated as having had an “ownership change” if there is more than a 50% increase in stock ownership during any three year “testing period” by “5% shareholders.”

In order to help us preserve the NOLs, our certificate of incorporation contains stock transfer restrictions designed to reduce the risk of an ownership change for purposes of Section 382 of the Code. We expect that the restrictions will remain in place for the foreseeable future. We cannot assure you, however, that these restrictions will prevent an ownership change.

The NOLs will expire in various amounts, if not used, between 2027 and 2032. The Internal Revenue Service (the “IRS”) has not audited any of our tax returns for any of the years during the carryforward period including those returns for the years in which the losses giving rise to the NOLs were reported. We cannot assure you that we would prevail if the IRS were to challenge the availability of the NOLs. If the IRS were successful in challenging our NOLs, all or some portion of the NOLs would not be available to offset our future consolidated income and we may not be able to pay taxes that may be due.

Inadequate liquidity could materially and adversely affect our business operations in the future.

If our cash flow and capital resources are insufficient to fund our obligations, we may be forced to reduce our capital expenditures, seek additional equity or debt capital or restructure our debt. We cannot assure you that any of these remedies could, if necessary, be affected on commercially reasonable terms, or at all. Our liquidity is constrained by our need to satisfy our obligations under our debt agreements and our Barclays supply and exchange agreements. The availability of capital when the need arises will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, the crack spread, natural gas and oil prices, our credit ratings, interest rates, market perceptions of us or the industries in which we operate, our market value and our operating performance. We may be unable to execute our long-term operating strategy if we cannot obtain capital from these sources when the need arises.

We may be unable to successfully identify, execute or effectively integrate future acquisitions which may negatively affect our results of operations.

We will continue to pursue acquisitions in the future. Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition or, if the acquisition occurs, effectively integrate the acquired business into our existing businesses. Negotiations of potential acquisitions and the integration of acquired business operations may require a disproportionate amount of management’s attention and our resources. Even if we complete additional acquisitions, continued acquisition financing may not be available or available on reasonable terms, any new businesses may not generate the anticipated level of revenues, the anticipated cost efficiencies or synergies may not be realized and these businesses may not be integrated successfully or operated profitably. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our results of operations.

Meeting the requirements of evolving environmental, health and safety laws and regulations including those related to climate change could adversely affect our performance.

Consistent with the experience of other U.S. refiners, environmental laws and regulations have raised operating costs and may require significant capital investments at our refinery. We believe that existing physical facilities at our refinery are substantially adequate to maintain compliance with existing applicable laws and regulatory requirements. However, we may be required to address conditions that may be discovered in the future and require a response. Also, potentially material expenditures could be required in the future as a result of evolving environmental, health and safety, and energy laws, regulations or requirements that may be adopted or imposed in the future. Future developments in federal and state laws and regulations governing environmental, health and safety and energy matters are especially difficult to predict.

Currently, multiple legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of consideration, promulgation or implementation. These include actions to develop national, statewide or regional programs, each of which could require reductions in our greenhouse gas emissions. Requiring reductions in our greenhouse gas emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse gas emissions programs, including acquiring emission credits or allotments.

Requiring reductions in our greenhouse gas emissions and increased use of renewable fuels which can be supplied by producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and individual customers could also decrease the demand for our refined products, and could have a material adverse impact on our business, financial condition and results of operations. For example:

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• The US EPA proposed regulations in 2009, that would require the reduction of emissions of greenhouse gases from light trucks and cars, and would establish permitting thresholds for stationary sources that emit greenhouse gases and require emissions controls for those sources. Promulgation of the final rule on April 1, 2010, has resulted in a cascade of related rulemakings by the US EPA pursuant to the Federal Clean Air Act (the “CAA”) relative to controlling greenhouse gas emissions.

• In December 2007, the Energy Independence and Security Act was enacted into federal law, which created a second renewable fuels standard. This standard requires the total volume of renewable transportation fuels (including ethanol and advanced biofuels) sold or introduced in the U.S. to reach 18.2 billion gallons in 2014 and to increase to 36 billion gallons by 2022. However, the US EPA has proposed to reduce the total renewable and advanced biofuel requirements to 15.2 billion in 2014.

•  In March 2014, the US 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 refineries nation-wide little time to engineer, permit, and implement substantial modifications.

In addition, the inability of third parties to manufacture advanced biofuels may prohibit us from meeting the requirements of the Energy Independence and Security Act of 2007.

Our common stock is not listed for trading on a national market and the market for our common stock has been historically illiquid, which may affect your ability to sell your shares.

Our common stock is not currently listed for trading on a national securities exchange. The volume of trading in our stock has historically been low. A substantial amount of our common stock is held by two investors who have restrictions on their ability to sell the stock. For example, during the fourth quarter of 2013, the average daily trading volume for our stock has been approximately 43,000 shares. Having a market for shares that are not listed for trading on a national market and without substantial liquidity can adversely affect the price of the stock at a time when you might want to sell your shares. We cannot assure investors that a more active trading market will develop even if we issue more equity in the future.

Concentrated stock ownership and a restrictive certificate of incorporation provision may discourage unsolicited acquisition proposals.

Zell Credit Opportunities Fund, L.P. (“ZCOF”) and Whitebox Advisors, LLC (“Whitebox”), together with their affiliates, each own or have the right to acquire as of the date hereof approximately 33.1% and 24.4% , respectively, or when aggregated, 57.5% of our outstanding common stock. The level of their combined ownership of shares of common stock could have the effect of discouraging or impeding an unsolicited acquisition proposal. In addition, the change in ownership limitations contained in Article 11 of our certificate of incorporation could have the effect of discouraging or impeding an unsolicited takeover proposal.

Future sales of our common stock may depress our stock price.

No prediction can be made as to the effect, if any, that future sales of our common stock, or the availability of our common stock for future sales, will have on the market price of our common stock. Sales in the public market of substantial amounts of our common stock, or the perception that such sales could occur, could adversely affect prevailing market prices for our common stock. The potential effect of these shares being sold may be to depress the price at which our common stock trades.

Our ability to generate cash and repay our indebtedness depends on many factors beyond our control, and any failure to do so could harm our business, financial condition and results of operations.

Our ability to fund future capital expenditures and repay our indebtedness when due will depend on our ability to generate sufficient cash flow from operations, borrowings under our debt agreements and distributions from our subsidiaries. To a certain extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions and other factors that are beyond our control, including the crack spread and the prices we receive for our natural gas and oil production.

We cannot assure you that our businesses will generate sufficient cash flow from operations, that our subsidiaries can or will make sufficient distributions to us or that future borrowings will be available to us in an amount sufficient to repay our indebtedness or fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our needs, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital or restructure our debt. We cannot assure you that any of these remedies could, if necessary, be affected on commercially reasonable terms, or at all, which could cause us to default on our obligations and could impair our liquidity.

We may be unable to compete effectively with larger companies for acquisitions, which could have a material adverse effect on our businesses, results of operations, and financial condition.

The industries in which we operate are intensely competitive, and we compete with other companies that have greater resources than we have. Our ability to acquire additional businesses or properties in the future will be dependent upon our ability to evaluate and select suitable businesses or properties for acquisition and to consummate transactions in a highly competitive environment. Many of our larger competitors carry on refining operations and market petroleum and other products and explore for and produce natural gas and oil, on a regional, national or worldwide basis. These companies may be able to pay more for acquisition targets, or evaluate or bid for and purchase a greater number of acquisition targets than our resources permit. Our inability to compete effectively with larger companies for acquisitions could have a material adverse effect on our business, results of operations, and financial condition.

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Competition from integrated national and international oil companies that produce their own supply of feedstocks, larger independent refiners and from high volume retailers and large convenience store retailing operators who may have greater financial resources, could materially affect our business, financial condition and results of operations.

We compete with a number of integrated national and international oil companies who produce crude oil, some of which is used in their refining operations. Unlike these oil companies, we must purchase all of our crude oil from unaffiliated sources. Because these oil companies benefit from increased commodity prices, and as other larger independent refining companies have greater access to capital and have stronger capital structures, they are able to better withstand poor and volatile market conditions, such as a lower refining margin environment, shortages of crude oil and other feedstocks or extreme price fluctuations.

We also face strong competition in the fuel and convenience store retailing market for the sale of retail gasoline and convenience store merchandise. Our competitors include service stations operated by integrated major oil companies and well-recognized national high volume retailers or regional large chain convenience store operators, often selling gasoline or merchandise at aggressively competitive prices.

Some of these competitors may have access to greater financial resources, which may provide them with a better ability to bear the economic risks inherent in all phases of our industry. Fundamental changes in the supply dynamics of foreign product imports could lead to reduced margins for the refined products we market, which could have an adverse effect on the profitability of our fuel retailing business.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to manage risks associated with our businesses and increase the working capital requirements to conduct these activities.

The Dodd-Frank Act provides for new statutory and regulatory requirements for derivative transactions, including oil and natural gas derivative transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. In October 2011, the CFTC approved final rules that establish position limits for futures contracts on 28 physical commodities, including four energy commodities, and swaps, futures and options that are economically equivalent to those contracts. The rules provide an exemption for “bona fide hedging” transactions or positions, but this exemption is narrower than the exemption under existing CFTC position limit rules. These newly approved CFTC position limits rules 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 positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

It is not possible at this time to predict with certainty the full effect of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act may require us to comply with margin requirements and with certain clearing and trade-execution requirements if we do not satisfy certain specific exceptions. The Dodd-Frank Act may also require the counterparties to our derivatives contracts to transfer or assign some of their derivatives contracts to a separate entity, which may not be as creditworthy as the current counterparty. Depending on the rules adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities derivative transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures. A requirement to post cash collateral could therefore reduce our ability to execute transactions to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Many of our refined products could cause serious injury or death if mishandled or misused by us or our purchasers, or if defects occur during manufacturing.

While we produce, store, transport and deliver all of our refined products in a safe manner, many of our refined products are highly flammable or explosive and could cause significant damage to persons or property if mishandled. Defects in our products (such as gasoline or jetfuel) or misuse by us or by end purchasers could lead to fatalities or serious damage to property. We may be held liable for such occurrences which could have a material adverse effect on our business and results of operations.

Our disclosure controls and procedures may not prevent or detect all acts of fraud.

Our disclosure controls and procedures are designed to reasonably assure that information required to be disclosed by us in reports we file or submit under the Exchange Act is accumulated and communicated to management, recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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Our management, including our Chief Executive Officer and Chief Financial Officer, believes that any disclosure controls and procedures or internal controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, they cannot provide absolute assurance that all control issues and instances of fraud, if any, within our companies have been prevented or detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by an unauthorized override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and we cannot assure you that any design will succeed in achieving its stated goals under all potential future conditions. Accordingly, because of the inherent limitations in a cost effective control system, misstatements due to error or fraud may occur and not be detected.

Failure to maintain an effective system of internal control over financial reporting may have an adverse effect on our stock price.

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the SEC to implement Section 404, we are required to furnish a report by our management to include in our annual reports on Form 10-K regarding the effectiveness of our internal control over financial reporting. This Annual Report includes, among other things, an assessment of the effectiveness of our internal control over financial reporting as of the end of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by management. During the fourth quarter of 2013, management of the company performed a comprehensive assessment of the design and operating effectiveness of internal control over financial reporting. In performing its assessment, management considered the number of late adjustments and corrections to the consolidated financial statements. As a result of this assessment, management concluded that it had a material weakness because it did not have sufficient qualified accounting personnel to prevent the company’s financial statements and related disclosures from being materially misstated. These material weaknesses had not been remedied as of December 31, 2013 and the effectiveness of our internal control over financial reporting in the future will depend on our ability to fulfill the steps to remediate these and other material weaknesses. If we are unable to assert that our internal control over financial reporting is effective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internal controls, we could lose investor confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price.

Adverse changes in global economic conditions and the demand for transportation fuels may impact our business and financial condition in ways that we currently cannot predict.

The U.S. economic recovery from the recent recession continues to be tenuous, and the risk of further significant global economic downturn continues. Further prolonged downturns or failure to recover could result in declines in consumer and business confidence and spending as well as increased unemployment and reduced demand for transportation fuels. This continues to adversely affect the business and economic environment in which we operate. These conditions increase the risks associated with the creditworthiness of our suppliers, customers and business partners. The consequences of such adverse effects could include interruptions or delays in our suppliers’ performance of our contracts, reductions and delays in customer purchases, delays in or the inability of customers to obtain financing to purchase our products, and bankruptcy of customers. Any of these events may adversely affect our cash flow, profitability and financial condition.

Our operations are subject to operational hazards that could expose us to potentially significant losses.

Our operations are subject to potential operational hazards and risks inherent in refining operations, in transporting and storing crude oil and refined products and in producing natural gas and oil. Any of these risks, such as fires, explosions, maritime disasters, security breaches, pipeline ruptures and spills, mechanical failure of equipment, and severe weather and natural disasters, at our or third party facilities could result in business interruptions or shutdowns and damage to our properties and the properties of others. A serious accident at our facilities could also result in serious injury or death to our employees or contractors and could expose us to significant liability for personal injury claims and reputational risk. Any such event or unplanned shutdown could have a material adverse effect on our business, financial condition and results of operations.

We carry property, casualty and business interruption insurance but such insurance may not provide coverage against all potential losses.

We carry property, casualty and business interruption insurance but we do not maintain insurance coverage against all potential losses. Marine vessel charter agreements do not include indemnity provisions for oil spills so we also carry marine charterer’s liability insurance. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance or failure by one or more insurers to honor its coverage commitments for an insured event could have a material adverse effect on our business, financial condition and results of operations.

Our insurance coverage may be inadequate to protect it from the liabilities that could arise in our business.

Although we maintain insurance overage against the risks related to our businesses, risks may arise for which we may not be insured.Claims covered by insurance are subject to deductibles, the aggregate amount of which could be material.Insurance policies are also subject to compliance with certain conditions, the failure of which could lead to a denial of coverage as to a particular claim or the voiding of a particular insurance policy.There also can be no assurance that existing insurance coverage can be renewed at commercially reasonable rates or that available coverage will be adequate to cover future claims.If a loss occurs that is partially or completely uninsured, we could be exposed to substantial liability.

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Our business is impacted by environmental risks of spills, discharges or other releases of petroleum or hazardous substances that are inherent in refining and production operations.

The operation of refineries, pipelines, and refined products terminals and the production of natural gas and oil is inherently subject to the risks of spills, discharges or other inadvertent releases of petroleum or hazardous substances. These events could occur in connection with our drilling and production activities and our refinery, pipelines, or refined products terminals, or in connection with any facilities which receive our waste or by-products for treatment or disposal. If any of these events occur, or is found to have previously occurred, we could be liable for costs and penalties associated with their remediation under federal, state and local environmental laws or common law, and could be liable for property damage to third parties caused by contamination from releases and spills. The penalties and clean-up costs that we may have to pay for releases or the amounts that we may have to pay to third parties for damages to their property, could be significant and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.

We operate in and adjacent to environmentally sensitive coastal waters where tanker, pipeline, and refined product transportation and storage operations are closely regulated by federal, state and local agencies and monitored by environmental interest groups. Transportation and storage of crude oil and refined products over and adjacent to water involves inherent risk and subjects us to the provisions of the Federal Oil Pollution Act of 1990 and state laws in Hawaii. Among other things, these laws require us and the owners of tankers that we charter to deliver crude oil to our refinery to demonstrate in some situations the capacity to respond to a spill of up to one million barrels of oil from a tanker and up to 600,000 barrels of oil from an above ground storage tank adjacent to water, which we refer to as a “Worst Case Discharge,” to the maximum extent possible.

We and the owners of tankers we charter have contracted with various spill response service companies in the areas in which we transport and store crude oil and refined products to meet the requirements of the Federal Oil Pollution Act of 1990 and state and foreign laws. However, there may be accidents involving tankers, pipelines, or above ground storage tanks transporting or storing crude oil or refined products, and response services may not respond to a Worst Case Discharge in a manner that will adequately contain that discharge, or we may be subject to liability in connection with a discharge. Additionally, we cannot ensure that all resources of a contracted response service company could be available for our or a chartered tanker owner’s use at any given time. There are many factors that could inhibit the availability of these resources, including, but not limited to, weather conditions, governmental regulations or other global events. By requirement of state or federal rulings, these resources could be diverted to respond to other global events.

Our operations are also subject to general environmental risks, expenses and liabilities which could affect our results of operations.

From time to time we have been, and presently are, subject to litigation and investigations with respect to environmental and related matters. We may become involved in further litigation or other proceedings, or we may be held responsible in any existing or future litigation or proceedings, the costs of which could be material.

We operate and have in the past operated retail stations with underground storage tanks in Hawaii. Federal and state regulations and legislation govern the storage tanks, and compliance with these requirements can be costly. The operation of underground storage tanks poses certain risks, including leaks. Leaks from underground storage tanks, which may occur at one or more of our retail stations, may impact soil or groundwater and could result in fines or civil liability for us.

Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations and limit our ability to react to changes in the economy or our industry.

We have, and will continue to have, a significant amount of indebtedness. Our obligation to repay our existing indebtedness will limit our ability to use our capital for other purposes. We may also incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop our businesses to the extent desired. A higher level of indebtedness and/or preferred stock would increase the risk that we may default on our obligations. Our ability to meet our debt obligations depends on our future performance. General economic conditions, the crack spread, natural gas and oil prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors that will affect our ability to raise cash through an offering of securities or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil and refined products.

Our refinery currently receives its crude oil via tankers and transports refined products from Oahu to Hawaii and Maui. In addition to environmental risks, we could experience an interruption of supply or an increased cost to deliver refined products to market if the ability of the pipelines or vessels to transport crude oil or refined products is disrupted because of accidents, governmental regulation or third-party action. A prolonged disruption of the ability of a pipeline or vessels to transport crude oil or refined products could have a material adverse effect on our business, financial condition and results of operations.

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We rely upon certain critical information systems for the operation of our business, and the failure of any critical information system, including a cyber-security breach, may result in harm to our business.

We are heavily dependent on our technology infrastructure and maintain and rely upon certain critical information systems for the effective operation of our business. These information systems include data network and telecommunications, internet access and our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our refinery and our pipelines and terminals. These information systems are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks, and other events. To the extent that these information systems are under our control, we have implemented measures such as virus protection software and intrusion detection systems, to address the outlined risks. However, security measures for information systems cannot be guaranteed to be failsafe. Any compromise of our data security or our inability to use or access these information systems at critical points in time could unfavorably impact the timely and efficient operation of our business and subject us to additional costs and liabilities, which could adversely affect our results of operations. Finally, federal legislation relating to cyber-security threats could impose additional requirements on our operations.

Our ability to operate our business effectively may suffer if we do not in a timely and cost effective manner establish our own financial, administrative, and other support functions related to the HIE Acquisition and we cannot assure you that the transitional services Tesoro agreed to provide us will be sufficient for our needs.

In connection with the HIE Acquisition, we have entered into a transition services agreement with Tesoro under which Tesoro is providing certain transitional services to us, including finance/accounting, tax, retail, operations, information technology, environmental, health and safety, marine, and human resources, and other services for a period of time. These services may not be sufficient to meet our needs. After our agreement with Tesoro expires, if we have not established our own support services related to the HIE Acquisition, we may not be able to obtain these services at favorable prices or on favorable terms, if at all.

Any failure or significant downtime in Tesoro’s financial, administrative, or other support systems during the transitional period could negatively impact our results of operations or prevent us from paying our suppliers and employees, or performing administrative or other services on a timely basis, which could negatively affect our results of operations.

Our ability to extract value from our investment in Piceance Energy is limited.

Our 33.34% ownership interest in Piceance Energy is a significant asset. Our operating income will therefore be dependent in part on the profitability of Piceance Energy and on the ability of Piceance Energy to make distributions to its owners, which is currently prohibited by the terms of the Piceance Energy Credit Facility. In addition, Laramie, which owns the remaining 66.66% ownership interest in Piceance Energy, controls most decisions affecting Piceance Energy’s operations and we only have veto rights over decisions of Piceance Energy in a limited number of areas.

We cannot control the activities on properties we do not operate and we are unable to ensure the proper operation and profitability of these non-operated properties.

We are a non-operator with respect to our natural gas and oil properties. Consequently, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of leasehold acquisition, drilling and development activities therefore will depend upon a number of factors outside of our control, including:

• timing and amount of capital expenditures;

• expertise and diligence in adequately performing operations and complying with applicable agreements;

• financial resources;

• inclusion of other participants in drilling wells; and

• use of technology.

As a result of any of the above or other failure of the operator to act in ways that are in our best interest, our results of operations could be adversely affected.

Information concerning our natural gas and oil reserves is uncertain.

There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of an estimate of quantities of natural gas and oil reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future natural gas and oil prices, availability and terms of financing, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities, natural gas and oil prices and regulatory changes. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from our assumptions and estimates. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same data. Further, the difficult financing environment may inhibit our ability to finance development of our reserves in the future.

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The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves as of December 31, 2013 included herein were prepared by independent reserve engineers in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves. As required by the SEC, the estimated discounted present value of future net cash flows from proved reserves is generally based on prices and costs as required by the SEC on the date of the estimate, while actual future prices and costs may be materially higher or lower. In addition, the 10% discount factor the SEC requires to be used to calculate discounted future net revenues for reporting purposes is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the natural gas and oil industry in general.

Through Piceance Energy, we are subject to all the risks of natural gas and oil exploration and production.

Although we are a non-operator, through our investment in Piceance Energy, and to a lesser extent, our other non-operated properties, we are exposed to all the risks inherent in natural gas and oil exploration and production, including the risks that:

• we may not be able to replace production with new reserves;

• exploration and development drilling may not result in commercially productive reserves;

• title to properties in which we or Piceance Energy has an interest may be impaired by title defects;

• the marketability of our natural gas products depends mostly on the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities, which are owned by third parties;

• we have no long-term contracts to sell natural gas and oil;

• federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays;

• natural gas drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water when it flows back to the wellbore. If we are unable to obtain adequate water supplies and dispose of the water we use or remove at a reasonable cost and within applicable environmental rules, our ability to produce natural gas commercially and in commercial quantities would be impaired.

Potential legislative and regulatory actions addressing climate change could increase our costs, reduce our revenue and cash flow from natural gas and oil sales or otherwise alter the way we conduct our business.

Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us. For example, the US EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the US EPA to begin regulating emissions of GHGs under existing provisions of the CAA. The US EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered and may in the future consider “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. For those sources of GHGs that are unable to meet the required limitations, such legislation could impose substantial financial burdens. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.

Adverse results of legal proceedings could materially adversely affect us.

We are subject to and may in the future be subject to a variety of legal proceedings and claims that arise out of the ordinary conduct of our business.Results of legal proceedings cannot be predicted with certainty.Irrespective of its merits, litigation may be both lengthy and disruptive to the company’s operations and may cause significant expenditures and diversion of management attention.We may be faced with significant monetary damages or injunctive relief that could materially adversely affect our business operations or materially and adversely affect our financial position and results of operations should we fail to prevail in certain matters.

Negative publicity may adversely impact us.

Media coverage and public statements that insinuate improper actions by the company, regardless of their factual accuracy or truthfulness, may result in negative publicity, litigation or investigations by regulators.Addressing negative publicity and any resulting litigation or investigations may distract management, increase costs and divert resources.Negative publicity may have an adverse impact on our reputation and the morale of our employees, which could adversely affect our financial position and results of operations.

Events outside the United States could create operating risks.

United States embargoes or restrictive actions by U.S. and foreign governments could limit our ability to purchase crude oil and buy and sell petroleum products.Changes in, or the imposition of, withholding or other taxes on foreign income, tariffs or restriction on foreign trade and investment, political instability, war and civil disturbances or other events such as terrorist attacks, piracy and kidnapping may limit or disrupt markets, could negatively impact our ability to purchase crude oil or sell our refined products.

Item  1B. UNRESOLVED STAFF COMMENTS

None.

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Item  2. PROPERTIES

See “Item 1 – Business” for the location and general character of the properties used in our refining, distribution and marketing segment. Our corporate headquarters are located at 800 Gessner Road, Suite 875, Houston, Texas 77024. We believe that these properties and facilities are adequate for our operations and are maintained in a good state of repair.

Natural Gas and Oil Properties

Piceance Energy

All of the assets held byPiceance Energy are located in Garfield and Mesa Counties,Colorado. All of the natural gas and oil reserves associated with such assets produce primarily from the Mesaverde Formation and to a lesser extent the Mancos Formation, and some of the acreage is contiguous. The geology of the Piceance Basin is characterized as highly consistent and predictable over large areas, which generally equates to reliable timing and cost expectations during drilling and completion activities, as well as minimal well-to-well variance in production and reserves when completed with the same methodology. Laramie and its predecessor company have drilled over 300 natural gas wells with over a 99% success rate in the Piceance Basin.

Encana Operated Wells

We have a 5% working interest in 22 wells in the southern region of the Piceance Basin. These wells are operated by Encana and were obtained in February 2008 from Encana.

Point Arguello and Rocky Point Units

We own the equivalent of a 6.07% gross working interest in the Point Arguello Unit and related facilities located offshore California in the Santa Barbara Channel. Within this unit, there are three producing platforms (Hidalgo, Harvest and Hermosa). We also own a 6.25% working interest in the development of the eastern half of OCS Block 451 in the Rocky Point Unit.

Reserves

For a table presenting the estimated natural gas and oil reserves we own directly or indirectly through Piceance Energy, see “Item 1. – Business – Natural Gas and Oil Operations.”

Internal Controls Over Reserve Estimates, Technical Qualifications and Technologies Used

Our policies regarding internal controls over reserve estimates require reserves to be in compliance with the SEC definitions and guidance, and for reserve estimates to be prepared by an independent third party reserve engineering firm and reviewed by certain members of senior management. The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Dan Paul Smith and Mr. John Hattner. Mr. Smith has been practicing consulting petroleum engineering at NSAI since 1980. Mr. Smith is a Licensed Professional Engineer in the State of Texas (License No. 49093) and has over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner has been practicing consulting petroleum geology at NSAI since 1991. Mr. Hattner is a Licensed Professional Geoscientist in the State of Texas, Geology, (License No. 559) and has over 30 years of practical experience in petroleum geosciences, with over 20 years experience in the estimation and evaluation of reserves. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary’s College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. A letter which identifies the professional qualifications of the individuals at NSAI who were responsible for overseeing the preparation of our reserve estimates as of December 31, 2013 has been filed as a part of Exhibit 99.1 to this Annual Report.

A variety of methodologies were used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, analog type curve analysis, volumetrics, material balance, pressure transient analysis, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

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Proved Undeveloped Reserves

Substantially all of our proved undeveloped reserves at December 31, 2013 are held through our minority equity ownership in Piceance Energy. As we are not the operator of these properties, we cannot predict or control the timing of the development of the properties.

Production Volumes, Unit Prices and Costs

The following table sets forth certain information regarding our volumes of production sold and average prices received associated with our production and sales of natural gas and crude oil for year ended December 31, 2013, the respective periods in 2012 and the year ended December 31, 2011.

	Successor				Predecessor
			Period from		Period from
	Year Ended		September 1		January 1		Year Ended
	December 31,		through		through		December 31,
	2013		December 31, 2012		August 31, 2012		2011
Company:
Production volume -
Total production (MMcfe)		668		139		5,256		11,682
Production from continuing operations:
Oil (MBbls)		69		22		67		140
Natural Gas (MMcf)		253		9		4,852		9,948
Total (MMcfe)		668		139		5,256		10,788
Net average daily production-continuing operations:
Oil (Bbl)		189		177		277		385
Natural Gas (Mcf)		694		77		19,966		27,254
Average sales price:
Oil (per Bbl)	$	98.29	$	97.66	$	96.60	$	80.16
Natural Gas (per Mcf)	$	5.35	$	4.32	$	3.42	$	5.29
Hedge gain (loss) (per Mcfe)	$	—	$	—	$	—	$	(0.04)
Lease operating costs—(per Mcfe)	$	8.50	$	11.22	$	1.72	$	1.27
Company Share of Piceance Energy:
Production volume -
Total production (MMcfe)		4,978		1,711
Production from continuing operations:
Oil (MBbls)		16		6
NGLs (MBbls)		143		48
Natural Gas (MMcf)		4,029		1,391
Total (MMcfe)		4,978		1,711
Net average daily production-continuing operations:
Oil (Bbl)		43		46
NGLs (Bbl)		391		391
Natural Gas (Mcf)		11,038		11,404
Average sales price:
Oil (Per Bbl)	$	85.91	$	77.81
NGLs (Per Bbl)	$	30.08	$	36.09
Natural Gas (per Mcf)	$	3.66	$	3.09
Hedge gain (loss) (per Mcfe)	$	(0.05)	$	(0.18)
Lease operating costs—(per Mcfe)	$	0.60	$	0.53

Productive Wells and Acreage

The table below shows, as of December 31, 2013, the approximate number of gross and net producing oil and gas wells by state and their related developed acres owned by us, as well as our share of gross and net wells and developed acres related to our 33.34% equity ownership in Piceance Energy. Calculations include 100% of wells and acreage owned by us and our subsidiaries. Developed acreage consists of acres spaced or assignable to productive wells.

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	Productive Wells
	Oil (1)				Gas (1)				Developed Acres
Location	Gross (2)		Net (3)		Gross (2)		Net (3)		Gross (2)		Net (3)
Company:
California (offshore)		34		2.10		—		—		2,422		147
Colorado		—		—		21		1.05		210		11
New Mexico(4)		9		0.11		1		0.01		800		9
Total		43		2.21		22		1.06		3,432		167
Company’s Share of Piceance Energy
Colorado (5)		—		—		525		102.83		10,319		3,018
Total		43		2.21		547		103.89		13,751		3,185

(1)	Some of the wells classified as “oil” wells also produce minor amounts of natural gas. Likewise, some of the wells classified as “gas” wells also produce minor amounts of oil.
(2)	A “gross well” or “gross acre” is a well or acre in which a working interest is held. The number of gross wells or acres is the total number of wells or acres in which a working interest is owned.
(3)	A “net well” or “net acre” is deemed to exist when the sum of fractional ownership interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof.
(4)	Our ownership interest in New Mexico wells is an overriding royalty interest.
(5)	For our 33.34% equity interest in Piceance Energy, the net wells and net developed acres are reflected as if we owned our interest directly.

Undeveloped Acreage

At December 31, 2013, we held undeveloped acreage in Colorado as set forth below:

	Undeveloped Acres (1)(2)
Location	Gross		Net
Company		—		—
Company share of Piceance Energy (3)		38,858		10,481

(1)	Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves.
(2)	There are no material near-term lease expirations for which the carrying value at December 31, 2013 has not already been impaired in consideration of these expirations or capital budgeted to convert acreage to held by production.
(3)	For our 33.34% equity interest in Piceance Energy, the net undeveloped acres are reflected as if we owned our interest directly.

Drilling Activity

During the year ended December 31, 2013, the respective periods in 2012 and the year ended December 31, 2011, we drilled or participated in the drilling of the following productive and nonproductive exploratory and development wells:

	Successor								Predecessor
					September 1				January 1
	Year Ended				Through				Through				Year Ended
	December 31, 2013				December 31, 2012				August 31, 2012				December 31, 2011
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Company
Exploratory Wells (1):
Productive:
Oil		—		—		—		—		—		—		—		—
Natural Gas		—		—		—		—		1		0.32		1		1
Nonproductive		—		—		—		—		—		—		1		1
Total		—		—		—		—		1		0.32		2		2

(1) Does not include wells in which we had only a royalty interest.

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	Successor								Predecessor
					September 1				January 1
	Year Ended				Through				Through				Year Ended
	December 31, 2013				December 31, 2012				August 31, 2012				December 31, 2011
Company	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Development Wells (1):
Productive:
Oil		3		0.03		—		—		—		—		—		—
Natural Gas		13		0.65		8		0.40		—		—		41		1.96
Nonproductive		—		—		—		—		—		—		—		—
Total		16		0.68		8		0.40		—		—		41		1.96
Total Wells (1):
Productive:
Oil		3		0.03		—		—		—		—		—		—
Natural Gas		13		0.65		8		0.40		1		0.32		42		2.96
Nonproductive		—		—		—		—		—		—		1		1
Total Wells		16		0.68		8		0.40		1		0.32		43		3.96

(1) Does not include exploratory wells in progress.

Piceance Energy did not drill any exploratory or development wells during the year ended December 31, 2013 and the period from September 1 through December 31, 2012.

Present Drilling Activity

Piceance Energy completed 9 natural gas wells in 2013 that were drilled during 2012 and prior. Piceance had no drilling activity in 2013. Encana drilled and completed 13 natural gas wells during 2013 to complete a 21 well drilling program which commenced during 2012 subsequent to our emergence from Bankruptcy. The operator of our New Mexico properties drilled three oil wells in 2013 in which we have overriding royalty interests.

Delivery Commitments

We had no material delivery commitments as of December 31, 2013.

Item  3. LEGAL PROCEEDINGS

Consent Decree.Tesoro is currently negotiating a Consent Decree with the US 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 the refinery. It is anticipated that the Consent Decree will be finalized sometime during 2014 and will require certain capital improvements to the refinery to reduce emissions of air pollutants.

It is not possible at this time to estimate the cost of compliance with the final decree. 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 omissions of Tesoro or HIE prior to the Closing Date. Tesoro’s obligation to reimburse HIE for such fines is not subject to a monetary limitation; however, this obligation terminates on the third anniversary of the Closing Date. See “Business-Environmental Agreement – Consent Decree.”

Helicopter Litigation. HIE is the defendant in a lawsuit styled State of Hawaii Department of Transportation Airports Division et al. v. Tesoro Hawaii, Civil No. 09-2253-09 JHC. In this matter, the insurance company for the State of Hawaii is seeking reimbursement of the attorney’s fees and costs incurred by outside council to defend against Tesoro Hawaii’s third-party complaints for contribution in three previously-settled underlying litigation matters. The underlying litigation was filed by three helicopter tour operators flying on the Island of Kauau. The helicopter tour operators allege bad jet fuel caused the formation of coking deposits in their engines which resulted in millions of dollars of repair costs and lost income. There were no in-flight issues.

Tesoro Hawaii filed third-party complaints against the State of Hawaii in each of the three underlying lawsuits alleging that any fuel issues arose from improper design and maintenance of the underground pipeline and dispensers owned and maintained by the State of Hawaii. The helicopter operators settled with the State of Hawaii, and Tesoro Hawaii and its aviation liability insurers subsequently settled with the helicopter operators.

The lawsuit alleges that the State of Hawaii was entitled to a defense and indemnity under the terms of its lease for the Tesoro Hawaii facility at the Lihue airport. The suit alleges defense costs of approximately $2 million in the underlying lawsuits. The State of Hawaii and its insurance company have since demanded $3.25 million. The issue at trial is ultimately whether Tesoro Hawaii owed a contractual duty to pay for the State of Hawaii’s defense against Tesoro Hawaii’s third-party complaints against the State of Hawaii for the State’s own negligence. The case is set for a bench trial in September 2014.

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There is a companion lawsuit by the State of Hawaii and its insurance company against Tesoro Hawaii’s former liability insurer on the same issues. The Court previously held by way of a Motion for Summary Judgment that Tesoro Hawaii’s insurer had a duty to defend the State of Hawaii against Tesoro Hawaii’s third-party complaints. That matter is going to trial in July 2014 on the issue of damages only (e.g. the reasonable amount of attorney’s fees and costs the State of Hawaii is entitled to for the defense of the third-Party Complaints in the underlying lawsuits).

We do not believe that any loss relating to this litigation is probable. However, should any loss become probable before the end of the measurement period, such loss would be reflected as a purchase price adjustment relating to the HIE Acquisition.

Other. From time to time, we may be involved in other litigation relating to claims arising out of our operations in the normal course of our business. As of the date of this Annual Report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows. Any litigation pending at the time we emerged from Chapter 11 was transferred to the General Trust for resolution and settlement. For more information, see “Part I – Item 1. – Business—Bankruptcy and Plan of Reorganization – General Recovery Trust and Wapiti Trust.”

Item  4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

Item  5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information; Dividends

Our common stock currently trades under the symbol “PARR” on the OTCQB Marketplace. Prior to the Emergence Date, Delta’s common stock traded under the symbol “DPTRQ.” On August 31, 2012, pursuant to the Plan, Delta’s previously outstanding common stock was cancelled and we issued 14.8 million shares of common stock to settle unsecured claims pursuant to the Plan.

The high and low sale prices for our common stock for the most recent two fiscal years are shown in the table below. The prices per share of our common stock prior to the 1:10 reverse stock split effective for trading purposes on January 29, 2014 have been adjusted to reflect this stock split on a retroactive basis and may not represent actual transactions. The prices per share of our Predecessor’s shares were not adjusted.

Quarter Ended	High		Low
Predecessor:
March 31, 2012	$	0.68	$	0.08
June 30, 2012		0.61		0.08
July 1, 2012 through August 31, 2012		0.05		0.05
Successor:
September 1, 2012 through September 30, 2012		14.50		10.05
December 31, 2012		12.00		10.20
March 31, 2013		14.50		10.00
June 30, 2013		17.70		13.60
September 30, 2013		19.40		16.10
December 31, 2013		25.00		18.50

As of March 26, 2014, there were 196 common stockholders of record. On March 26, 2014, the closing price of our common stock was $21.05 on the OTCQB Marketplace. We have not paid dividends on our common stock, and we do not expect to do so in the foreseeable future. Our current debt agreements restrict the payment of dividends. In addition, as long as any obligations remain outstanding under the Loan Agreement, we are prohibited from paying dividends.

Recent Sales of Unregistered Securities

During the year ended December 31, 2013, we did not have any sales of securities in transactions that were not registered under the Securities Act that have not been reported in a Form 8-K or Form 10-Q.

Issuer Purchases of Equity Securities

During the year, 12,657 vested shares were witheld to pay for the taxes due at vesting.The witheld shares had an aggregate value of $733 thousand.There were no other stock repurchases during the year ended December 31, 2013.

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Item 6. SELECTED FINANCIAL DATA

Not applicable to smaller reporting companies.

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

Overview

We emerged from the bankruptcy of Delta Petroleum in August 2012. The reorganization converted approximately $265 million of unsecured debt to equity and allowed us to preserve significant tax attributes. As required by U.S. generally accepted accounting principles we adopted fresh-start reporting as of the Emergence Date, resulting in us becoming a new entity for financial reporting purposes.See “- Reorganization under Chapter 11” and “- Fresh-Start Reporting and the Effects of the Plan”.

We currently operate in three segments:

• refining, distribution and marketing;

• natural gas and oil operations; and

• commodity marketing and logistics

Our refining, distribution and marketing segment owns and operates a refinery rated at 94,000 barrels per day of throughput capacity in Kapolei, Hawaii, 2.4 million barrels of crude oil and feedstock storage and 2.5 million barrels of refined product storage.The refinery produces ultra-low sulfur diesel, gasoline, jet fuel, marine fuel and other associated refined products primarily for consumption in Hawaii. Our refinery logistics assets include five refined products terminals, 27 miles of pipelines, a single point mooring and other associated logistics assets. In addition, we distribute our products through 31 retail outlets located across the islands of Oahu, Maui and Hawaii. Results of operations in our refinery segment depend on favorable "crack spreads", or the difference between the price we pay for crude oil, sourced internationally, and the prices we receive for our refined products, which are primarily determined by the local Hawaii market.

Our natural gas and oil assets are non-operated and are concentrated in our 33.34% ownership of Piceance Energy, a joint venture entity operated by Laramie and focused on producing natural gas in Garfield and Mesa Counties, Colorado.The estimated value of Piceance Energy’s estimated proved reserves was $89.3 million at December 31, 2013. In addition, we own non-operating interests in Colorado and offshore California, and an overriding royalty interest in New Mexico.We estimate the value of estimated proved reserves for these additional properties to be approximately $3.5 million at December 31, 2013.Our interests are heavily weighted towards natural gas and natural gas liquids.

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.Our logistics capabilities consist of historical pipeline shipping status (giving us assured pipeline access) a leased rail car fleet and experience in contracted chartering of tugs and barges.We contract to provide logistics services for others and trade for our own account. Our success primarily depends on favorable spreads between the discounted crudes available from the Western U.S. and Canada and the prices we receive from our customers.

Due to significant acquisitions in December 2012 and September 2013 and our emergence from bankruptcy in August 2012, our consolidated results of operations for any period after December 31, 2013 will not be comparable to any prior period.We will continue to recognize our proportional share of the earnings or losses of Piceance Energy, which will be driven by drilling results and market prices.We will also continue to reflect results of operations of our commodity marketing and logistics segment, which will be dependent primarily on marketing and transportation revenues and will be driven by price differentials along the crude oil supply chain.However, we anticipate our future 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. Crack spreads will be the primary driver of the refinery's results of operations and therefore, of our own profitability.

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2013 Results

Results of operations for the periods discussed in “- Results of Operations” are presented in the table below (in thousands):

	Successor				Predecessor
	Year Ended December 31, 2013		September 1 through December 31, 2012		January 1, 2012 through August 31, 2012
Refining, distribution and marketing revenues	$	778,126	$	—	$	—
Commodity marketing and logistics		100,149		—		—
Oil and gas sales		7,739		2,144		23,079
Total revenues		886,014		2,144		23,079
Cost of revenues		848,924		—		—
Operating expense, excluding depreciation, depletion, and amortization expense shown separately below		27,251		—		—
Lease operating expense		5,627		1,684		9,038
Transportation expense		—		—		6,963
Production taxes		49		4		979
Exploration expense		—		—		2
Dry hole costs and impairments		—		—		151,347
Depreciation, depletion, amortization and accretion		5,982		401		16,041
Trust litigation and settlements		6,206		—		—
General and administrative expense		21,494		4,520		9,386
Acquisition and integration costs		9,794		556		—
Total operating expenses		925,372		7,165		193,756
Operating loss		(39,313)		(5,021)		(170,677)
Loss from unconsolidated affiliates		(2,941)		(1,325)		(20)
Interest expense and financing costs, net		(19,471)		(1,056)		(6,852)
Other income		808		86		516
Change in value of common stock warrants		(10,114)		(4,280)		—
Gain on derivative instruments, net		410		—		—
Income tax benefit		—		2,757		—
Loss from continuing operations		(70,621)		(8,839)		(177,033)
Reorganization items:
Professional fees and administrative costs		—		—		22,354
Changes in asset fair values due to fresh start accounting adjustments		—		—		14,765
Gain on settlement of senior debt		—		—		(166,144)
Gain on settlement of liabilities		—		—		(2,571)
Net loss	$	(70,621)	$	(8,839)	$	(45,437)

Contributors to 2013 Results

Results of operations for the quarter and year ended December 31, 2013 reflect the acquisition, integration and operation of HIE which we acquired on September 25, 2013. Our gross margin was impacted by our out of cycle feedstock purchases during the refinery start up, exacerbated by tensions in Libya and Syria. The majority of the feedstocks consumed during the fourth quarter were procured during the refinery start up in order to restock the supply chain before the closing of the acquisition. Market crack spreads (or the margin between the price paid for of crude oil and the price received for refined products) declined in the fourth quarter of 2013 compared to the fourth quarter of 2012 and the third quarter of 2013. We believe our refinery’s economics reflect components of both Singapore and West Coast refineries. Average crack spreads for the Singapore and San Francisco markets declined $1.07 and $4.17 per barrel, respectively, for the fourth quarter of 2013 from the fourth quarter of 2012, in each case using a Brent 4:1:2:1 index (or one part gasoline, two parts distillate and one part fuel oil). In addition, since the acquisition, we have relied heavily on third party service providers as well as a transition services agreement with the former owner as we build internal infrastructure, contributing to elevated G&A expenses.

We believe that our efforts to rationalize the sourcing of our crude oil should improve our margins and that reducing our dependence on third party service providers as well as the transition services agreement should lower relative G&A expenses.

 

Reorganization under Chapter 11

In December 2011 and January 2012, Delta and its subsidiaries filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Delta and its subsidiaries included in the bankruptcy petitions are collectively referred to as the “Debtors.”

In March 2012, the Debtors obtained approval from the bankruptcy court to proceed with Laramie Energy II, LLC (“Laramie”) as the sponsor of a plan of reorganization (the “Plan”). In June 2012, Delta entered into a contribution agreement (the “Contribution Agreement”) with a new joint venture formed by Delta, Laramie and Piceance Energy LLC (“Piceance Energy”) to effect the transactions contemplated by Plan.

On August 31, 2012 (the “Emergence Date”), Delta consummated the transactions contemplated by the Contribution Agreement and each of Delta and Laramie contributed to Piceance Energy their respective natural gas and oil assets in the Piceance Basin. Piceance Energy is owned 66.66% by Laramie and 33.34% by Delta.

At the closing, Piceance Energy entered into a new credit agreement, borrowed $100 million under that agreement, and distributed approximately $72.6 million net of settlements to the company and approximately $24.9 million to Laramie. The company used its distribution to pay bankruptcy expenses and to repay secured debt. The company also entered into a new credit facility and borrowed $13 million under that facility at closing, and used those funds primarily to pay bankruptcy claims and expenses.

Following the reorganization, the company retained its interest in the Point Arguello Unit offshore California and other miscellaneous assets and certain tax attributes, including significant net operating loss carryforwards. Based upon the Plan as confirmed by the bankruptcy court, Delta’s creditors were issued approximately 14.8 million shares of common stock, and Delta’s former stockholders received no consideration under the Plan.

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On the Emergence Date, Delta also amended and restated its certificate of incorporation and bylaws and changed its name to “Par Petroleum Corporation.” The amended and restated certificate of incorporation contains restrictions that render void certain transfers of our stock that involve a holder of five percent or more of our shares. The purpose of this provision is to preserve certain of our tax attributes that we believe may have value.

Fresh-Start Reporting and the Effects of the Plan

As required by U.S. GAAP, effective as of August 31, 2012, Par adopted fresh-start reporting because (i) holders of voting shares immediately before confirmation of the Plan received less than 50% of the emerging entity and (ii) the reorganization value of our assets immediately before confirmation of the Plan was less than our post-petition liabilities and allowed claims. Fresh-start reporting results in a new basis of accounting and reflects the allocation of our estimated fair value to underlying assets and liabilities. Fresh-start reporting results in us becoming a new entity for financial reporting purposes. Accordingly, our consolidated financial statements for periods prior to August 31, 2012 reflect the operations of Delta prior to reorganization (hereinafter also referred to as the “Predecessor”) and are not comparable to the consolidated financial statements presented on or after August 31, 2012. Accordingly, certain disclosures relating to the Predecessor’s financial statements for the eight months ended August 31, 2012 have been omitted.

Results of Operations

Successor year ended December 31, 2013 compared to Successor four months ended December 31, 2012 and Predecessor eight months ended August 31, 2012

The 2013 and 2012 periods lack comparability due to the application of fresh-start accounting effective August 31, 2012, the contribution of the majority of our natural gas and oil assets to Piceance Energy effective August 31, 2012, our acquisition of Texadian effective December 31, 2012 and our acquisition of HIE effective September 25, 2013.

Net Loss. Net loss was approximately $70.6 million, or a loss of $3.57 per basic and diluted common share, for the year ended December 31, 2013, compared to a net loss of approximately $8.8 million, or a loss of $0.56 per basic and diluted common share, for the four months ended December 31, 2012 and a net loss of approximately $45.4 million, or a loss of $1.57 per basic and diluted common share, for the eight months ended August 31, 2012.

Operating Revenues. For the year ended December 31, 2013, our operating revenues were approximately $878.3 million, consisting of refining and distribution and marketing revenues totaling approximately $778.1 million and commodity marketing and logistics revenues of approximately $100.1 million. There were no such revenues in the periods prior to December 31, 2012 due to HIE and Texadian being acquired effective September 25, 2013 and December 31, 2012, respectively.

Natural Gas and Oil Sales. For the year ended December 31, 2013, natural gas and oil sales was approximately $7.7 million. For the four months ended December 31, 2012 and eight months ended August 31, 2012, natural gas and oil sales were approximately $2.1 million and $23.1 million, respectively. The increase in natural gas and oil sales for the year ended December 31, 2013 compared to the four months ended December 31, 2012 is primarily due to the inclusion of 12 months activity in 2013 compared to four months of activity in 2012.The decrease in natural gas and oil sales for the year ended December 31, 2013 compared to the eight months ended August 31, 2012 is primarily related to the contribution of the majority of our natural gas and oil assets to Piceance Energy on August 31, 2012 in connection with our emergence from bankruptcy.

Cost of Revenues. For the year ended December 31, 2013, our cost of revenues was approximately $848.9 million consisting of refining distribution costs totaling approximately $765.0 million and commodity marketing and logistics costs of approximately $83.9 million. There were no such expenses in the periods prior to December 31, 2012 due to HIE and Texadian being acquired effective September 25, 2013 and December 31, 2012, respectively. 

Lease Operating Expense. For the year ended December 31, 2013, lease operating expense was approximately $5.6 million. For the four months ended December 31, 2012 and eight months ended August 31, 2012, lease operating expense was approximately $1.7 million and $9.0 million, respectively. The increase in lease operating expense for the year ended December 31, 2013 compared to the four months ended December 31, 2012 is primarily due to the inclusion of 12 months activity in 2013 compared to four months of activity in 2012.The decrease in lease operating expense for the year ended December 31, 2013 compared to the eight months ended August 31, 2012 is primarily related to the contribution of the majority of our natural gas and oil assets to Piceance Energy on August 31, 2012 in connection with our emergence from bankruptcy.

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Transportation Expense. For the year ended December 31, 2013 and the four months ended December 31, 2012, we incurred no transportation expense.   For the eight months ended August 31, 2012, transportation expense was approximately $7.0 million. The decrease is primarily related to the contribution of the majority of our natural gas and oil assets to Piceance Energy on August 31, 2012 in connection with our emergence from bankruptcy.

Production Taxes. For the year ended December 31, 2013, production taxes were approximately $49 thousand. For the four months ended December 31, 2012 and eight months ended August 31, 2012, production taxes were approximately $4 thousand and $979 thousand, respectively. The increase in production taxes for the year ended December 31, 2013 compared to the four months ended December 31, 2012 is primarily due to the inclusion of 12 months activity in 2013 compared to four months of activity in 2012.The decrease in production taxes for the year ended December 31, 2013 compared to the eight months ended August 31, 2012 is primarily related to the contribution of the majority of our natural gas and oil assets to Piceance Energy on August 31, 2012 in connection with our emergence from bankruptcy.

Dry Hole Costs and Impairments. For the year ended December 31, 2013 and the four months ended December 31, 2012, we incurred no dry hole costs or impairment expense.   Dry hole costs and impairments for the eight month period ended August 31, 2012 were approximately $151.3 million. On August 31, 2012, concurrent with the approval of the Plan, our natural gas and oil properties were reclassified to assets held for sale resulting in an impairment of approximately $151.3 million.Subsequent to the contribution of the majority of our natural gas and oil assets to Piceance Energy, we hold solely non-operated interests in natural gas and oil properties and have not participated in any exploratory drilling activities.

Depreciation, Depletion, Amortization and Accretion. For the year ended December 31, 2013, depreciation, depletion, amortization and accretion (“DD&A”) expense was approximately $6.0 million, which consisted primarily of $2.3 million for our refining, distribution and marketing business, $2.0 million for our commodity marketing and logistics business, approximately $1.7 million for our natural gas and oil operations and approximately $20 thousand relating to corporate. For the four months ended December 31, 2012 and eight months ended August 31, 2012, DD&A expense was approximately $401 thousand and $16 million, respectively and primarily related to our natural gas and oil activities. The increase in DD&A expense related to our refining and distribution business and our marketing and transportation business is due to the HIE acquisition and the Texadian acquisition on September 25, 2013 and December 31, 2012, respectively.The increase in DD&A expense for the year ended December 31, 2013 compared to the four months ended December 31, 2012 is primarily due to the inclusion of 12 months activity in 2013 compared to four months of activity in 2012.The decrease in DD&A expense for the year ended December 31, 2013 compared to the eight months ended August 31, 2012 is primarily related to the contribution of the majority of our natural gas and oil assets to Piceance Energy on August 31, 2012 in connection with our emergence from bankruptcy.

Trust Litigation and Settlements. For the year ended December 31, 2013, trust litigation and settlement expense was approximately $6.2 million and consisted of legal and other professional fees relating to the Recovery Trust of approximately $519 thousand and revisions to the settlement claim liability of approximately $5.7 million based on the claims settled during the period.

General and Administrative Expense. For the year ended December 31, 2013, general and administrative expense was approximately $21.5 million. For the four months ended December 31, 2012 and eight months ended August 31, 2012, general and administrative expense was approximately $4.5 million and $9.4 million, respectively. General and administrative costs were higher in 2013 due to the growth of the company, costs related to contractors, and costs related to the transition services agreement. 

Acquisition and Integration Costs. For the year ended December 31, 2013 and 2012, were $9.8 million and $556 thousand. Of the $9.8 million recorded in 2013, $7.0 million is specific to acquisition costs and $2.8 million is related to integration costs.

Loss From Unconsolidated Affiliates. For the year ended December 31, 2013, our loss from Piceance Energy totaled approximately $2.9 million consisting of an allocated loss of $3.5 million partially offset by an accretion of the basis difference in the investment of approximately $575 thousand. The allocated loss includes an operating loss of approximately $2.3 million and financing and derivative costs of approximately $1.2 million. For the four months ended December 31, 2012, our allocated loss from our investment in Piceance Energy was approximately $1.3 million, which includes a loss of approximately $699 thousand from operating activities and financing and derivative loss of approximately $626 thousand. There was no significant loss from unconsolidated affiliates for the Predecessor as Piceance Energy was formed in connection with our emergence from bankruptcy on August 31, 2012.

Interest Expense and Financing Costs. For the year ended December 31, 2013, our interest expense and financing costs was approximately $19.5 million. For the four months ended December 31, 2012 and eight months ended August 31, 2012, interest expense and financing costs were approximately $1.1 million and $6.9 million, respectively. Our Predecessor and its subsidiaries filed bankruptcy petitions in December 2011 and January 2012.As a result, we ceased accruing interest on the Predecessor’s outstanding debt, except for the debtor-in-possession financing loan.The consummation of the Plan of Reorganization on August 31, 2012 resulted in a new capital structure.Furthermore, we have entered into various credit agreements related to the HIE acquisition and Texadian acquisition to support their related operations which have increased interest costs relative to prior periods.

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Change in value of common stock warrants. For the year ended December 31, 2013, we recognized a loss related to the change in value of common stock warrants of approximately $10.1 million due to mark-to-market adjustments resulting from an increase in the price of our common stock. For the four months ended December 31, 2012, we recognized an unrealized loss of approximately $4.3 million due to mark-to-market adjustments resulting from an increase in the price of our common stock. These derivatives did not exist prior to our emergence from bankruptcy.

Gain on Derivative Instruments, net. For the year ended December 31, 2013, we recognized a gain primarily related to our derivative instruments of approximately $410 thousand due to mark-to-market adjustments.These derivatives did not exist prior to our emergence from bankruptcy.

Other Income. For the year ended December 31, 2013, other income totaled approximately $809 thousand. Other income for the four months ended December 31, 2012 was not significant. For the eight months ended August 31, 2012, other income was approximately $516 thousand.

Income Taxes. For the year ended December 31, 2013, we recorded no tax expense. For the four months ended December 31, 2012, we recorded a net income tax benefit of approximately $2.8 million, which represents the reduction in our valuation allowance as a result of deferred tax liabilities recorded in connection with the Texadian acquisition.

As of December 31, 2013, there was insufficient evidence for us to conclude that it was more likely than not that the deferred tax asset would be realized.

Reorganization Items. For the eight months ended August 31, 2012, we recognized approximately $22.4 million in professional fees and administrative expenses, a loss of approximately $14.8 million relating to a change in fair value of assets due to fresh-start reporting adjustments, and a gain on the extinguishment of debt of approximately $168.7 million related to the settlement of our senior debt and other liabilities. There are no reorganization items in periods subsequent to August 31, 2012.

Liquidity and Capital Resources

Our primary sources of liquidity are our cash flows from operations and borrowing availability under our credit facilities, as more fully described below. We believe that our cash flows from operations and available capital resources will be sufficient to meet our capital expenditure, working capital, and debt service requirements for the next twelve months. However, our ability to generate sufficient cash flow from operations depends, in part, on market prices for oil and refined products and general economic, political and other factors beyond our control. We believe we could, during periods of economic downturn, access the capital markets and/or other available financial resources or reduce our capital and discretionary expenditure plans to strengthen our financial position.

Current Liquidity. The following table summarizes our liquidity position as of March 25, 2014 and December 31, 2013 (in thousands):

	Refining Distribution and Marketing		Commodity Marketing and Logistics		Other		Total
March 25, 2014
Cash and cash equivalents (1)	$	9,680	$	10,773	$	2,216	$	22,669
Revolver availability		5,000		—		—		5,000
ABL Facility		33,134		18,491		—		51,625
Total available liquidity	$	47,814	$	29,264	$	2,216	$	79,294

	Refining Distribution and Marketing		Commodity Marketing and Logistics		Other		Total
December 31, 2013
Cash and cash equivalents (1)	$	4,536	$	24,009	$	9,516	$	38,061
Revolver availability		5,000		—		—		5,000
ABL Facility		28,436		8,420		—		36,856
Total available liquidity	$	37,972	$	32,429	$	9,516	$	79,917

(1) The HIE, HIE Retail and Texadian credit agreements contain certain covenants that limit our ability to distribute cash to their parent or other subsidiaries.

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. Since the Emergence Date, 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.

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We may be required to fund capital contributions of up to $20 million to Piceance Energy under the Piceance Energy LLC Agreement. We expect that our capital contributions will be funded from available cash on hand and possible equity contributions from certain existing stockholders. If our cash sources are not sufficient to fund our entire capital contribution, then our equity ownership interest in Piceance Energy may be reduced or diluted to the extent of our shortfall.

 Private Placement Equity Transaction

On September 13, 2013, we entered into a Common Stock Purchase Agreement pursuant to which we agreed to sell shares of our common stock at a price of $13.90, as adjusted to reflect the one for ten reverse stock split effective for trading purposes on January 29, 2014 (the “Reverse Stock Split”) per share in a private placement transaction (the “Private Placement”) in reliance upon an exemption from registration pursuant to Regulation D under the Securities Act of 1933. Certain purchasers, namely, ZCOF Par Petroleum Holdings, L.L.C., an affiliate of Zell Credit Opportunities Master Fund, L.P. (“ZCOF”), and affiliates of Whitebox Advisors, LLC (“Whitebox”), each owned 10% or more of the our common stock directly or through affiliates prior to the execution of the Common Stock Purchase Agreement and are deemed to be our affiliates as a result of such ownership. ZCOF and Whitebox have representatives on our board of directors.

On September 25, 2013, we completed the Private Placement and issued approximately 14.4 million shares of common stock resulting in aggregate gross proceeds to us of approximately $200 million. We did not engage any investment advisors with respect to the Private Placement, and no finders’ fees or commissions were paid to any party in connection therewith. The proceeds from the Private Placement were used to fund a portion of the purchase price for the HIE acquisition.

Delayed Draw Term Loan Credit Agreement

Pursuant to the Plan, on the Emergence Date, we and certain of our subsidiaries (the “Guarantors” and, together with the company, the “Loan Parties”) entered into a Delayed Draw Term Loan Credit Agreement (the “Loan Agreement”) with Jefferies Finance LLC, as administrative agent (the “Agent”) for the lenders party thereto from time to time, including WB Delta, Ltd., Waterstone Offshore ER Fund, Ltd., Prime Capital Master SPC, GOT WAT MAC Segregated Portfolio, Waterstone Market Neutral MAC51, Ltd., Waterstone Market Neutral Master Fund, Ltd., Waterstone MF Fund, Ltd., Nomura Waterstone Market Neutral Fund, ZCOF Par Petroleum Holdings, L.L.C. and Highbridge International, LLC (collectively, the “Lenders”), pursuant to which the Lenders agreed to extend credit to us in the form of term loans (each, a “Loan” and collectively, the “Loans”) of up to $30 million. We borrowed $13 million on the Emergence Date in order to, along with the proceeds from the Contribution Agreement: (i) repay the loans and obligations due under the Predecessor’s secured debtor-in-possession credit facility, and (ii) pay allowed but unpaid administrative expenses to the Debtors related to the Plan. During 2013, we borrowed an additional $17 million for general corporate use.  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.

Amendment to the Loan Agreement

 On December 28, 2012, in order to fund a portion of the purchase price for our acquisition of Texadian Energy, the Loan Parties entered into an amendment to the Loan Agreement with the Agent and the Lenders, pursuant to which certain lenders (the “Tranche B Lenders”) agreed to extend additional borrowings to us (the “Tranche B Loan”). The total commitment of the Tranche B Loan of $35 million was drawn at closing. In addition to funding a portion of the purchase price of the acquisition of Texadian, the Tranche B Loan provided cash collateral for our former cash collateralized letter of credit facility. Pursuant to the Eighth Amendment to the Loan Agreement entered into on July 24, 2013, the Lenders refinanced and replaced the Tranche B Loan with new Tranche B Loans in the aggregate principal amount of $65 million (the “New Tranche B Loans”). The proceeds from the New Tranche B Loans were applied to prepay in full the Tranche B Loan, to make payments due under the membership interests purchase agreement in connection with the acquisition of HIE (the “HIE Purchase Agreement”), and for working capital and general corporate purposes.

 On September 25, 2013 and in connection with the acquisition of HIE, we entered into a Tenth Amendment to the Loan Agreement pursuant to which the Lenders (i) consented to the consummation of the transactions contemplated by the HIE Purchase Agreement and the use of a portion of the proceeds from the Private Placement to fund a portion of the consideration for the acquisition of HIE and for certain other purposes, (ii) provided certain other consents in connection with the transactions contemplated by the HIE Purchase Agreement, (iii) increased the interest rate applicable to certain of the loans, and (iv) amended certain provisions of the Loan Agreement and the other loan documents in connection with the consummation of the transactions contemplated by the HIE Purchase Agreement and the Private Placement.

 The consent provided by the Lenders was conditioned on, among other things, (i) the repayment in full of the New Tranche B Loans owing to all Lenders except for ZCOF Par Petroleum Holdings, L.L.C., and a partial repayment of the New Tranche B Loans owing to ZCOF Par Petroleum Holdings, L.L.C. from a portion of the proceeds from the Private Placement and (ii) a portion of the proceeds from the Private Placement being used to consummate the transactions contemplated by the HIE Purchase Agreement.

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The term loans (other than the New Tranche B Loans that remain outstanding following the repayment described above) under the Loan Agreement bore interest (a) from September 25, 2013 through October 31, 2013, at a rate equal to 9.75% per annum payable, at the election of the company, either (i) in cash or (ii) in-kind, and (b) from and after November 1, 2013, at a rate equal to 14.75% per annum payable either (i) in cash or (ii) in-kind.These term loans were repaid in full in November 2013.

The New Tranche B Loans bear interest (a) from June 24, 2013 through October 31, 2013 at a rate equal to 9.75% per annum payable, at the election of the company, either (i) in cash or (ii) in kind, and (b) from and after November 1, 2013, at a rate equal to 14.75% per annum payable either (i) in cash or (ii) in kind. Additionally, we agreed to pay the New Tranche B Lenders a nonrefundable exit fee equal to 2.5% of the aggregate amount of the New Tranche B Loans. The exit fee is earned in full and payable on the maturity date of the Tranche B Loans or, if earlier, the date on which the New Tranche B Loans are paid in full.

The New Tranche B Loans mature and are payable in full on August 31, 2016.We may prepay the New Tranche B Loans at any time, provided that any prepayment is in an integral multiple of $100,000 and not less than $100,000 or, if less, the outstanding principal amount of the New Tranche B Loans. Amounts to be applied to prepayment of New Tranche B Loans shall be applied (i) first, towards payment of interest then outstanding and fees then due, and (ii) second, towards payment of principal then outstanding.

 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.

ABL Facility

On September 25, 2013 and in connection with the with the acquisition of Tesoro Hawaii, HIE and certain subsidiaries of HIE (the “ABL Borrowers”) and Hawaii Pacific Energy entered into an asset-based revolving credit facility (the “ABL Facility”) to provide the ABL Borrowers with a senior secured revolving credit facility of up to $125 million under which the ABL Borrowers may borrow amounts from time to time based on the available borrowing base as determined in accordance with the ABL Facility. The ABL Facility also allows the ABL Borrowers to use up to $50 million of availability under the ABL Facility for the issuances of letters of credit. The amounts borrowed pursuant the ABL Facility and all obligations arising under the ABL Facility are secured by a lien on substantially all of HIE’s assets.  The ABL Borrowers agreed to pay an up-front fee, an origination fee, and commitment fees for the ABL Facility.  The ABL Borrowers borrowed $15 million on September 25, 2013 under the ABL Facility in order to, in part, (i) fund the purchase price under the HIE Purchase Agreement, and (ii) provide working capital to the ABL Borrowers. The proceeds from any future amounts borrowed pursuant to the ABL Facility will be used for general corporate purposes and to fund the working capital of the ABL Borrowers.  All loans and other obligations outstanding under the ABL Facility are payable in full on September 25, 2017. The ABL Facility requires HIE and its subsidiaries and Hawaii Pacific Energy to comply with various affirmative and negative covenants affecting its business and operations, including compliance by HIE in certain circumstances with a minimum ratio of consolidated earnings before interest, taxes, depreciation and amortization (“EBITDA”), as adjusted, to total fixed charges of 1.0 to 1.0.

HIE Retail Credit Agreement

On November 14, 2013, HIE Retail, LLC (“HIE Retail”), our subsidiary, entered into a Credit Agreement (the “Retail Credit Agreement”) in the form of a senior secured term loan of up to $30 million (the “Term Loan”) and a senior secured revolving line of credit of up to $5 million (the “Revolver”). The Lenders initially advanced $26 million of the Term Loan at the closing and will advance an additional $4 million of the Term Loan upon HIE Retail’s compliance with certain liquor licensing requirements, if such requirements are satisfied prior to December 31, 2014. The proceeds of the Term Loan are available for general corporate purposes. 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 retail outlets on the islands of Oahu, Maui and Hawaii. HIE Retail agreed to pay the lenders an upfront and an annual agent fee beginning on November 14, 2014.  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.   The Term Loan matures and is fully payable on November 14, 2020. Principal on the Term Loan will be repaid in 28 equal quarterly principal payments over the term.  The Revolver matures on November 14, 2016. Letters of credit issued under the Revolver are not to expire beyond the maturity date of the Revolver.  A percentage of annual cash flow may be applied to the outstanding principal balance of the Term Loan begins with fiscal year 2014 if the leverage ratio exceeds 4.5:1.00.

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Texadian Uncommitted Credit Agreement

On June 12, 2013, Texadian and its wholly-owned subsidiary Texadian Canada entered into an uncommitted credit agreement (the “Uncommitted Credit Agreement”) that provides 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, 2013, Texadian was in compliance with these covenants.There was $41.6 million outstanding in letters of credit as of December 31,2013.

Warrant Issuance Agreement

 Pursuant to the Plan of Reorganization, on the Emergence Date, we issued to the lenders under the Loan Agreement warrants (the “Warrants”) to purchase up to an aggregate of 959,213 shares of our common stock (the “Warrant Shares”). In connection with the issuance of the Warrants, we also entered into a Warrant Issuance Agreement, dated as of the Emergence Date (the “Warrant Issuance Agreement”). Subject to the terms of the Warrant Issuance Agreement, the holders are entitled to purchase shares of common stock upon exercise of the Warrants at an exercise price of $0.10 per share of common stock (the “Exercise Price”), subject to certain adjustments from time to time as provided in the Warrant Issuance Agreement. The Warrants expire on the earlier of (i) August 31, 2022 or (ii) the occurrence of certain merger or consolidation transactions specified in the Warrant Issuance Agreement. A holder may exercise the Warrants by paying the applicable exercise price in cash or on a cashless basis.

The Warrant Issuance Agreement includes certain restrictions on the transfer by holders of their Warrants, including, among others, that (i) the Warrants and the notes under the Loan Agreement are not detachable for transfer purposes, and for as long as obligations under the Loan Agreement are outstanding, the notes and Warrants may not be transferred separately, and (ii) in the event that any holder desires to transfer any pro rata portion of the notes and Warrants, then such holder must provide the other Lenders and/or holders of the Warrants with a right of first offer to make an election to purchase such offered notes and Warrants.

The number of shares of our common stock issuable upon exercise of the Warrants and the exercise prices of the Warrants will be adjusted in connection with certain issuances or sales of shares of the company’s common stock and convertible securities, or any subdivision, reclassification or combinations of common stock. Additionally, in the case of any reclassification or capital reorganization of the capital stock of the company, the holder of each Warrant outstanding immediately prior to the occurrence of such reclassification or reorganization shall have the right to receive upon exercise of the applicable Warrant, the kind and amount of stock, other securities, cash or other property that such holder would have received if such Warrant had been exercised.

From the Emergence Date through December 31, 2013, we issued an additional 208,460 shares of our common stock to settle bankruptcy matters. This entitles the Lenders to receive an additional 14,859 Warrant Shares as of December 31, 2013. On December 12, 2013, Warrants to purchase 183,389 Warrant Shares were exercised.At December 31, 2013, Warrants to purchase an aggregate of 790,683 Warrant Shares were outstanding.

Cash Flows

	Successor				Predecessor
	Year Ended December 31, 2013		September 1 through December 31, 2012		January 1 though August 31, 2012
			(In thousands)
Net cash provided by (used in) operating activities	$	(35,677)	$	(4,636)	$	(20,262)
Net cash provided by (used in) investing activities	$	(564,500)	$	(17,690)	$	72,622
Net cash provided by financing activities	$	632,053	$	23,629	$	(60,340)

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 $70.6 million offset by non-cash charges to operations of approximately $37.1 million and working capital changes of approximately $2.1 million. Net cash used in operating activities for the four months ended December 31, 2012 and eight months ended August 31, 2012 was approximately $4.6 million and $20.3 million, respectively. The operations of the 2012 and 2013 periods are not comparable due to the contribution of the majority of our natural gas and oil assets to Piceance Energy and the application of fresh - start accounting effective August 31, 2012, our acquisition of Texadian on December 31, 2012 and our acquisition of HIE on September 25, 2013.

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For the year ended December 31, 2013, net cash used in investing activities was primarily related to the acquisition of HIE for approximately $564.5 million, of which approximately $378.2 million was funded from the Supply and Exchange Agreements (see below), capitalized drilling costs and additions to property and equipment totaling approximately $8.1 million partially offset by proceeds of the sale of our assets held for sale of approximately $2.9 million. For the four months ended December 31, 2012, net cash used in investing activities was primarily related to our acquisition of Texadian and totaled approximately $17.4 million. Net cash provided by investing activities was approximately $72.6 million in the eight months ended August 31, 2012 and was generated from the proceeds of the sale of our oil and gas assets to Piceance Energy for approximately $74.2 million ($72.6 million net after working capital adjustments made in subsequent periods).

Net cash provided by financing activities for the year ended December 31, 2013 of approximately $632.1 million resulting from advances from our supply and exchange agreements totaling approximately $378.2 million, the sale of common stock totaling approximately $199.2 million, additional borrowings under our debt agreements of approximately $159.8 million and the release of approximately $19 million from restricted cash held to secure letters of credit partially offset by repayment of borrowings of approximately $121.9 million and payment of loan issue costs of approximately $2.3 million. For the four months ended December 31, 2012, net cash provided by financing activities totaled $23.6 million and was primarily related to borrowing of $35.0 million under our Tranche B Loan, the release of $5.2 million of restricted cash by the Recovery Trusts, as discussed under “—Commitments and Contingencies” below, an additional $2.4 million generated by recoveries from the Wapiti Trust, offset by a required deposit of $19 million to support letters of credit. Net cash used in financing activities was approximately $60.3 million in the eight months ended August 31, 2012. During the eight months ended August 31, 2012, we borrowed (i) approximately $13 million under our Loan Agreement on the Emergence Date, and (ii) approximately $10 million, and then repaid approximately $59.5 million under the senior secured debt-in-possession credit facility entered into by the Predecessor and reserved an additional $21.8 million in order to extinguish liabilities relating to the bankruptcy and funded the Wapiti and General Recovery Trusts with $2.0 million.

Capital Expenditures

Our capital expenditures excluding acquisitions for the year ended December 31, 2013 totaled approximately $7.8 million and was primarily related to our refinery and information technology systems.

Additional capital may be required to maintain our interests at our Point Arguello Unit offshore California, but this is currently unestimatable. Furthermore, we may be required as part of our equity investment in Piceance Energy to contribute up to an aggregate of approximately $20.0 million if approved by the majority of its board of managers. 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. We entered into the Supply and Exchange Agreements 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.Additionally, Barclays holds title to a majority of our refined product inventory in our tanks at the Refinery. We hold title to the inventory during the refining process.Barclays sells the crude oil 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 volumes at period-end in excess of the Block Volume, we record a liability for the Block Volume valued at the per barrel carrying value of the refined product inventory owned by Barclays.From time to time, we may sell refined product inventory that causes our refined product inventory to be less than the Block Volume.To the extent of this shortfall, we record a liability for the volumes that we would need to purchase at current market prices in order to meet the Block Volume requirement. The liability related to the Supply and Exchange Agreements is included in obligations under supply and exchange agreements on our consolidated balance sheets.

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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.

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.

Regulation of Greenhouse Gases. The United States Environmental Protection Agency (“US EPA”) has begun regulating greenhouse gases under the Clean Air Act Amendments of 1990 (the “Clean Air Act”).  New construction or material expansions that meet certain greenhouse gas emissions thresholds will likely require that, among other things, a greenhouse gas 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 greenhouse gas emissions. 

Furthermore, the US EPA is currently developing refinery-specific greenhouse gas regulations and performance standards that are expected to impose, on new and modified operations, greenhouse gas 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.

In 2007, the State of Hawaii passed Act 234, which required that greenhouse gas emissions be rolled back on a state wide 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 greenhouse gas emissions were reported to the US 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 greenhouse gas 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 greenhouse gas 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 (the “RFS2”). In August 2012, the US 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 US 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 US 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 US 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.

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In March 2014, the US 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 nation-wide 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.

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 (the “Closing Date”), Hawaii Pacific Energy (a wholly-owned subsidiary of Par created for purposes of the Tesoro Acquisition), Tesoro and HIE entered into an Environmental Agreement (the “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 US 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 finalized sometime during 2014 and will require certain capital improvements to our refinery to reduce emissions of air pollutants.

It is not possible at this time to estimate the cost of compliance with the final decree. 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 has agreed, at its expense, to replace the existing underground storage tanks at certain retail locations.

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, 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.

Tesoro’s indemnification obligations are subject to certain limitations as set forth in the Environmental Agreement.

Bankruptcy Matters

On the date we emerged from bankruptcy, or the Emergence Date, two trusts were formed, the Wapiti Trust and the Delta Petroleum General Recovery Trust (the “General Trust,” and together with the Wapiti Trust, the “Recovery Trusts”). The Recovery Trusts were 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 Recovery Trusts were funded with $1 million each pursuant to the Plan.

The General Trust is pursuing all bankruptcy causes of action not otherwise vested in the Wapiti Trust, 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 (the “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.

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From the Emergence Date through December 31, 2013, the Recovery Trusts have 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. The entire $5.2 million was released prior to December 31, 2012.

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, 2012, the Recovery Trustee settled 25 claims with an aggregate face amount of $6.6 million for $258,905 in cash and 20,275 shares of common stock.  Pursuant to the Plan, during the year ended December 31, 2013, the Recovery Trustee settled an additional 59 claims with an aggregate face amount of $26.9 million for approximately $5.4 million in cash and 208,460 shares of common stock.

As of December 31, 2013, it is estimated that a total of 28 claims totaling approximately $40.2 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, 2013, we have reserved approximately $3.8 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at period end (see Note 13 – Commitments and Contingencies to our audited consolidated financial statements).

Operating Leases

Within our refining, distribution and marketing 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
2013	$	22,725
2014		13,277
2015		12,362
2016		10,375
2017		9,244
Thereafter		25,614
Total minimum rental payments	$	93,597

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Capital Leases

Within our refining, distribution and marketing 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):

2013	$	382
2014		382
2015		382
2016		382
2017		382
Thereafter		840
Total minimum lease payments		2,750
Less amount representing interest		829
Total minimum rental payments	$	1,921

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 analyze our estimates, including those related to fresh start accounting adjustments, 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.

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. There is a significant amount of judgment involved in cash-flow estimates. 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 used a variety of methods to estimate fair value of our acquired assets and the value assigned to assets and liabilities in business combinations and in the application of fresh-start reporting, including 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.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.

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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.

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 it will not net settle.  Should we not designate a contract as a normal purchase or normal sale then 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. We elect to offset amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. As a result, our consolidated balance sheets present derivative assets and liabilities on a net basis. As of December 31, 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. As of December 31, 2012, we did not elect this exemption for our open contracts which were settled in the first quarter of 2013.

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.

As a part of the Plan of Reorganization, 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 reported in earnings.

 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, distribution and marketing business’ refinery and 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 are recorded in depreciation, depletion and amortization in the 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 statements of consolidated 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 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.

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.

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, 2013 and 2012, our aggregate natural gas and oil imbalances were not material to our consolidated financial statements. Additionally, we provide an accrual for natural gas and oil sales using the sales method by estimating natural gas and oil volumes and prices for months in which revenues have not been received using production and pricing information provided by the operator.

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Commodity Marketing and Logistics. We earn revenues from the sale and transportation of oil and the rental of rail cars. 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.

Refining, Distribution and Marketing. 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 sales in our statements of consolidated operations on a net basis. These transactions include 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 statements of consolidated operations, while the related transportation costs are included in cost of sales or operating expenses. Federal excise and state motor fuel taxes, which are remitted to governmental agencies through our refining segment and collected from customers in our retail segment, are included in both revenues and cost of sales in our statements of consolidated operations.

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.

We enter into exchange and supply contracts whereby we agree to deliver a particular quantity and quality of refined products at a specified location and date to a particular counterparty and to receive from the same counterparty a particular quantity and quality of refined products at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash each month. These transactions are not recorded as revenue because they involve the exchange of refined product inventories held for sale in the ordinary course of business to facilitate sales to customers. The exchange transactions are recognized at the carrying amount of the inventory transferred plus or minus any cash settlement due to grade or location differentials.

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 2010, 2011, and 2012. 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. 

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Item  7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required for smaller reporting companies.

Item  8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial statements begin on page F-1. There are no financial statement schedules since they are either not applicable or the information is included in the notes to the financial statements.

Item  9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

None.

Item 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

In connection with the preparation of this Annual Report on Form 10-K, as of December 31, 2013, an evaluation was performed under the supervision and with the participation of the company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 15d-15(e) under the Exchange Act of 1934. In performing this evaluation, management reviewed the selection, application and monitoring of our historical accounting policies. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures were not effective as of December 31, 2013. In designing and evaluating disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. Management is required to apply judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of our management, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under this framework, our management concluded that our internal control over financial reporting was not effective as of December 31, 2013.

Prior to December 31, 2011, we filed for voluntary bankruptcy and during the duration of the proceedings, our’s ability to maintain effective internal control over financial reporting was weakened due to a high amount of turnover to its accounting staff. As of August 31, 2012, we emerged from bankruptcy and replaced the operations and financial reporting functions with a new accounting group.In December 2012 and September 2013, we completed acquisitions which significantly increased the size of the company and its resource requirements.Due to our rapid growth there has been a heavy reliance on external service providers and contractors, particularly in the accounting department.

During the fourth quarter of 2013, management performed a comprehensive assessment of the design and operating effectiveness of internal control over financial reporting. In performing its assessment, management considered the number of late adjustments and corrections to the consolidated financial statements.As a result of this assessment, management concluded that it had a material weakness because it did not have sufficient qualified accounting personnel to prevent our financial statements and related disclosures from being materially misstated.

Changes in Internal Controls over Financial Reporting

There have been no significant changes during the quarter ended December 31, 2013 in our internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financing reporting.

As a result of the material weakness, management determined that the company needed to hire additional finance and accounting personnel to ensure it had adequate resources to perform the accounting functions and, to the extent external service providers and contractors continue to be used, adequately supervise those resources to prevent the financial statements and related disclosures from being materially misstated. We hired a new Chief Financial Officer in December 2013, and hired a Corporate Controller and additional accounting staff in early 2014 to enhance controls and procedures in the accounting function.The internal control gap remediation to be performed by management is ongoing and was not completed as of December 31, 2013; therefore, management has concluded that a material weakness exists in the operating effectiveness of its internal control over financial reporting.

43

 

No Attestation Report of the Registered Public Accounting Firm

This Annual Report on Form 10-K does not include an attestation report of the company’s independent registered public accounting firm regarding the company’s internal control over financial reporting. Management’s report was not subject to attestation by the company’s independent registered public accounting firm pursuant to an exemption for smaller reporting companies under Section 989G of the Dodd-Frank Act. We qualify for the Dodd-Frank Act exemption from the independent auditor attestation requirement under Section 404(b) of the Sarbanes-Oxley Act for small issuers that are neither a large accelerated filer nor an accelerated filer.

Item  9B. OTHER INFORMATION

None.

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated in this Annual Report on Form 10-K by reference to [our definitive proxy statement] or an amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission not later than 120 days after the close of our fiscal year ended December 31, 2013.

Item 11. EXECUTIVE COMPENSATION

The information required by this item is incorporated in this Annual Report on Form 10-K by reference to [our definitive proxy statement] or an amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission not later than 120 days after the close of our fiscal year ended December 31, 2013. 

Item  12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item is incorporated in this Annual Report on Form 10-K by reference to [our definitive proxy statement] or an amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission not later than 120 days after the close of our fiscal year ended December 31, 2013.

Item  13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item is incorporated in this Annual Report on Form 10-K by reference to [our definitive proxy statement] or an amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission not later than 120 days after the close of our fiscal year ended December 31, 2013. 

Item  14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item is incorporated in this Annual Report on Form 10-K by reference to [our definitive proxy statement] or an amendment to this Annual Report on Form 10-K to be filed with the Securities and Exchange Commission not later than 120 days after the close of our fiscal year ended December 31, 2013. 

44

PART IV

Item  15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements.

	Page No.
Reports of Independent Registered Public Accounting Firms	F-1
Consolidated Balance Sheets	F-5
Consolidated Statements of Operations	F-6
Consolidated Statements of Changes in Stockholders’ Equity	F-7
Consolidated Statements of Cash Flows	F-8
Notes to Consolidated Financial Statements	F-9

(2) Financial Statement Schedules. None.

(3) Exhibits.

INDEX TO EXHIBITS

2.1	Third Amended Joint Chapter 11 Plan of Reorganization of Delta Petroleum Corporation and Its Debtor Affiliates dated August 13, 2012. Incorporated by reference to Exhibit 2.1 to the company’s Current Report on Form 8-K filed on September 7, 2012.****
2.2	Contribution Agreement, dated as of June 4, 2012, among Piceance Energy, LLC, Laramie Energy, LLC and the company. Incorporated by reference to Exhibit 2.2 to the company’s Current Report on Form 8-K filed on June 8, 2012.****
2.3	Purchase and Sale Agreement dated as of December 31, 2012, by and among the company, SEACOR Energy Holdings Inc., SEACOR Holdings Inc., and Gateway Terminals LLC. Incorporated by reference to Exhibit 2.1 to the company’s Current Report on Form 8-K filed on January 3, 2013.****
2.4	Membership Interest Purchase Agreement dated as at June 17, 2013, by and among Tesoro Corporation, Tesoro Hawaii, LLC and Hawaii Pacific Energy, LLC. Incorporated by reference to Exhibit 2.4 to the company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, filed on August 14, 2013.****
3.1	Amended and Restated Certificate of Incorporation of the company. Incorporated by reference to Exhibit 3.1 to the company’s Current Report on Form 8-K filed on September 7, 2012.
3.2	Certificate of Amendment to the Certificate of Incorporation of the company dated effective September 25, 2013. Incorporated by reference to Exhibit 3.1 to the company’s Current Report on Form 8-K filed on September 27, 2014.
3.3	Certificate of Amendment to Amended and Restated Certificate of Incorporation of the company dated January 23, 2014. Incorporated by reference to Exhibit 3.1 to the company’s Current Report on Form 8-K filed on January 23, 2014.
3.4	Amended and Restated Bylaws of the company. Incorporated by reference to Exhibit 3.2 to the company’s Current Report on Form 8-K filed on September 7, 2012.
4.1	Form of the company’s Common Stock Certificate. ***
4.2	Stockholders Agreement effective as of August 31, 2012, by and among the company, Zell Credit Opportunities Master Fund, L.P., Waterstone Capital Management, L.P., Pandora Select Partners, LP, Iam Mini-Fund 14 Limited, Whitebox Multi-Strategy Partners, LP, Whitebox Credit Arbitrage Partners, LP, HFR RVA Combined Master Trust, Whitebox Concentrated Convertible Arbitrage Partners, LP and Whitebox Asymmetric Partners, LP. Incorporated by reference to Exhibit 4.2 to the company’s Current Report on Form 8-K filed on September 7, 2012.
4.3	Registration Rights Agreement effective as of August 31, 2012, by and among the company, Zell Credit Opportunities Master Fund, L.P., Waterstone Capital Management, L.P., Pandora Select Partners, LP, Iam Mini-Fund 14 Limited, Whitebox Multi-Strategy Partners, LP, Whitebox Credit Arbitrage Partners, LP, HFR RVA Combined Master Trust, Whitebox Concentrated Convertible Arbitrage Partners, LP and Whitebox Asymmetric Partners, LP. Incorporated by reference to Exhibit 4.3 to the company’s Current Report on Form 8-K filed on September 7, 2012.
4.4	Warrant Issuance Agreement dated as of August 31, 2012, by and among the company and WB Delta, Ltd., Waterstone Offshore ER Fund, Ltd., Prime Capital Master SPC, GOT WAT MAC Segregated Portfolio, Waterstone Market Neutral MAC51, Ltd., Waterstone Market Neutral Master Fund, Ltd., Waterstone MF Fund, Ltd., Nomura Waterstone Market Neutral Fund, ZCOF Par Petroleum Holdings, L.L.C. and Highbridge International, LLC. Incorporated by reference to Exhibit 4.4 to the company’s Current Report on Form 8-K filed on September 7, 2012.

45

4.5	Form of Common Stock Purchase Warrant dated as of June 4, 2012. Incorporated by reference to Exhibit 4.5 to the company’s Current Report on Form 8-K filed on September 7, 2012.
4.6	Par Petroleum Corporation 2012 Long Term Incentive Plan. Incorporated by reference to Exhibit 4.1 to the company’s Registration Statement on Form S-8 filed on December 21, 2012.*

10.1	Delayed Draw Term Loan Credit Agreement dated as of August 31, 2012, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jefferies Finance LLC, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed on September 7, 2012.
10.2	First Amendment to Delayed Draw Term Loan Credit Agreement, Joinder, Waiver, Consent and Omnibus Amendment Agreement dated as of September 28, 2012, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jefferies Finance LLC, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K filed on March 27, 2013.
10.3	Waiver and Second Amendment to Delayed Draw Term Loan Credit Agreement, Joinder, Waiver, Consent and Omnibus Amendment Agreement dated as of November 29, 2012, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jefferies Finance LLC, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K filed on March 27, 2013.
10.4	Third Amendment to Delayed Draw Term Loan Credit Agreement, Joinder, Waiver, Consent and Omnibus Amendment Agreement dated as of December 28, 2012, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jefferies Finance LLC, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed on January 3, 2013.
10.5	Fourth Amendment to Delayed Draw Term Loan Credit Agreement dated as of April 19, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jefferies Finance LLC, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed on April 22, 2013.
10.6	Fifth Amendment to Delayed Draw Term Loan Credit Agreement dated as of June 4, 2013, by and among the company, the Guarantors party thereto, the lenders party thereto and Jeffries Finance LLC, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.2 to the company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, filed on August 14, 2013.
10.7	Sixth Amendment to Delayed Draw Term Loan Agreement dated as of June 12, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.2 to the company’s Current Report on Form 8-K filed on June 17, 2013.
10.8	Seventh Amendment to Delayed Draw Term Loan Agreement dated as of June 17, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.3 to the company’s Current Report on Form 8-K filed on June 17, 2013.
10.9	Eighth Amendment to Delayed Draw Term Loan Agreement dated as of June 14, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.1 to the company’s Current Report on Form 8-K filed on June 24, 2013.
10.10	Ninth Amendment to Delayed Draw Term Loan Agreement dated as of August 1, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.10 to the company’s Registration Statement on Form S-1 filed on November 22, 2013.
10.11	Tenth Amendment to Delayed Draw Term Loan Agreement dated as of September 25, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.8 to the company’s Current Report on Form 8-K filed on September 27, 2014.
10.12	Eleventh Amendment to Delayed Draw Term Loan Agreement dated as of January 23, 2014, by and among the company, the Guarantors party thereto, ZCOF Par Petroleum Holdings, L.L.C. and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.1 to the company’s Current Report on Form 8-K filed on January 23, 2014.
10.13	Amended and Restated Limited Liability company Agreement for Piceance Energy, LLC. Incorporated by reference to Exhibit 10.2 to the company’s Current Report on Form 8-K filed on September 7, 2012.

46

10.14	Credit Agreement dated as of June 4, 2012 among Piceance Energy, LLC, the financial institutions party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and Wells Fargo Bank, National Association, as syndication agent. Incorporated by reference to Exhibit 10.3 to the company’s Current Report on Form 8-K filed on September 7, 2012.
10.15	First Amendment to Credit Agreement dated August 31, 2012, by and among Piceance Energy, LLC, the financial institutions party thereto, and JPMorgan Chase Bank, N.A. Incorporated by reference to Exhibit 10.4 to the company’s Current Report on Form 8-K filed on September 7, 2012.
10.16	Wapiti Recovery Trust Agreement dated August 27, 2012, by and among the company, DPCA LLC, Delta Exploration company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc., Castle Texas Production Limited Partnership, Amber Resources company of Colorado, Castle Exploration company, Inc. and John T. Young. Incorporated by reference to Exhibit 10.5 to the company’s Current Report on Form 8-K filed on September 7, 2012.
10.17	Delta Petroleum General Recovery Trust Agreement dated August 27, 2012, by and among the company, DPCA LLC, Delta Exploration company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc., Castle Texas Production Limited. Partnership, Amber Resources company of Colorado, Castle Exploration company, Inc. and John T. Young. Incorporated by reference to Exhibit 10.6 to the company’s Current Report on Form 8-K filed on September 7, 2012.
10.18	Pledge Agreement dated August 31, 2012, by Par Piceance Energy Equity LLC in favor of Jefferies Finance LLC. Incorporated by reference to Exhibit 10.7 to the company’s Current Report on Form 8-K filed on September 7, 2012.
10.19	Intercreditor Agreement dated August 31, 2012, by and among JP Morgan Chase Bank, N.A., as administrative agent for the First Priority Secured Parties (as defined therein), Jefferies Finance LLC, as administrative agent for the Second Priority Secured Parties (as defined therein), the company and Par Piceance Energy Equity LLC. Incorporated by reference to Exhibit 10.8 to the company’s Current Report on Form 8-K filed on September 7, 2012.
10.20	Pledge and Security Agreement, dated August 31, 2012, by the company and certain of its subsidiaries in favor of Jefferies Finance LLC. Incorporated by reference to Exhibit 10.9 to the company’s Current Report on Form 8-K filed on September 7, 2012.
10.21	Letter of Credit Facility Agreement dated as of December 27, 2012, by and between the company and Compass Bank. Incorporated by reference to Exhibit 10.2 to the company’s Current Report on Form 8-K filed on January 3, 2013.
10.22	Form of Indemnification Agreement between the company and its Directors and Executive Officers. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed on October 19, 2012.*
10.23	Uncommitted Credit Agreement dated as of June 12, 2013, by and among Texadian Energy, Inc., Texadian Energy Canada Limited and BNP Paribas. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed in June 17, 2013.
10.24	Common Stock Purchase Agreement dated effective as of September 10, 2013, by and among the company and the Purchasers party thereto. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed in September 13, 2013.
10.25	Letter Agreement dated as of September 17, 2013 but effective as of January 1, 2013, by and between Whitebox Advisors, LLC and the company. Incorporated by reference to Exhibit 10.18 to the company’s Quarterly Report on Form 10-Q filed on November 14, 2013.
10.26	Letter Agreement dated as of September 17, 2013 but effective as of January 1, 2013, by and between Equity Group Investments and the company. Incorporated by reference to Exhibit 10.17 to the company’s Quarterly Report on Form 10-Q filed on November 14, 2013.
10.27	Framework Agreement dated as of September 25, 2013, by and among Hawaii Pacific Energy, LLC, Tesoro Hawaii, LLC and Barclays Bank PLC. Incorporated by reference to Exhibit 10.1 to the company’s Quarterly Report on Form 80K filed on September 27, 2013.
10.28	Storage and Services Agreement dated as of September 25, 2013, by and among Tesoro Hawaii, LLC and Barclays Bank PLC. Incorporated by reference to Exhibit 10.2 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.29	Agency and Advisory Agreement dated as of September 25, 2013, by and among Tesoro Hawaii, LLC and Barclays Bank PLC. Incorporated by reference to Exhibit 10.3 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.30	Inventory First Lien Security Agreement dated as of September 25, 2013, by and among Tesoro Hawaii, LLC and Wells Fargo Bank, N.A, as inventory collateral agent. Incorporated by reference to Exhibit 10.4 to the company’s Current Report on Form 8-K filed on September 27, 2013.

47

10.31	First Lien Mortgage dated as of September 25, 2013, by and among Tesoro Hawaii, LLC and Wells Fargo Bank, N.A, as inventory collateral agent. Incorporated by reference to Exhibit 10.5 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.32	Intercreditor Agreement dated as of September 25, 2013, by and among Barclays Bank PLC, Wells Fargo Bank, N.A, as inventory collateral agent, Deutsche Bank AG New York Branch, as ABL loan collateral agent and as administrative agent pursuant to the ABL Credit Agreement, Hawaii Pacific Energy, LLC, and Tesoro Hawaii, LLC. Incorporated by reference to Exhibit 10.6 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.33	Membership Interests First Lien Pledge Agreement dated as of September 25, 2013, by and between Hawaii Pacific Energy, LLC and Wells Fargo Bank, N.A, as inventory collateral agent. Incorporated by reference to Exhibit 10.7 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.34	ABL Credit Agreement dated as of September 25, 2013, by and among Tesoro Hawaii, LLC and other borrowers party thereto, Hawaii Pacific Energy, LLC, the Lenders party thereto and Deutsche Bank AG New York Branch, as administrative agent and ABL loan collateral agent. Incorporated by reference to Exhibit 10.9 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.35	ABL Loan Second Lien Security Agreement dated as of September 25, 2013, by and between Tesoro Hawaii, LLC and Wells Fargo Bank, National Association, as inventory collateral agent. Incorporated by reference to Exhibit 10.10 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.36	ABL Loan First Lien Security Agreement dated as of September 25, 2013, by and between Tesoro Hawaii, LLC and Deutsche Bank AG New York Branch, as ABL loan collateral agent. Incorporated by reference to Exhibit 10.11 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.37	Second Lien Mortgage dated as of September 25, 2013, by and between Tesoro Hawaii, LLC and Deutsche Bank AG New York Branch, as collateral agent. Incorporated by reference to Exhibit 10.12 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.38	Membership Interests Second Lien Pledge Agreement dated as of September 25, 2013, by and between Hawaii Pacific Energy, LLC and Deutsche Bank AG New York Branch, as ABL loan collateral agent. Incorporated by reference to Exhibit 10.13 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.39	Inventory Second Lien Security Agreement dated as of September 25, 2013, by and between Tesoro Hawaii, LLC and Deutsche Bank AG New York Branch, as collateral agent. Incorporated by reference to Exhibit 10.14 to the company’s Current Report on Form 8-K filed on September 27, 2013.
10.40	Environmental Agreement dated as of September 25, 2013, by and among Tesoro Corporation, Tesoro Hawaii, LLC and Hawaii Pacific Energy, LLC. Incorporated by reference to Exhibit 10.16 to the company’s Quarterly Report on Form 10-Q filed on November 14, 2013.
10.41	Credit Agreement dated as of November 14, 2013, by and among the company, the Lenders party thereto and Bank of Hawaii, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed on November 19, 2013.
14.1	Par Petroleum Corporation Code of Business Conduct and Ethics for Employees, Executive Officers and Directors, effective October 15, 2012. Incorporated by reference to Exhibit 14.1 to the company’s Current Report on Form 8-K filed on October 19, 2012.
21.1	Subsidiaries of the Registrant.***
23.1	Consent of Deloitte & Touche LLP***
23.2	Consent of EKS&H LLLP***
23.3	Consent of KPMG LLP***
23.4	Consent of Netherland, Sewell & Associates, Inc.***

48

31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. ***
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. ***
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350.***
32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350. ***
99.1	Report of Netherland, Sewell & Associates, Inc. regarding the registrants Proved Reserves as of December 31, 2013.***
99.2	Agreement of Settlement and Release dated September 19, 2012, by and between The Wapiti Recovery Trust and Wapiti Oil & Gas, L.L.C. Incorporated by reference to Exhibit 99.1 to the company’s Current Report on Form 8-K filed on September 25, 2013.
101.INS	XBRL Instance Document.**
101.SCH	XBRL Taxonomy Extension Schema Documents.**
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.**
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.**
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.**
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.**

*	Management contracts and compensatory plans.
**	These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.
***	Filed herewith.
****	Schedules and similar attachments to this agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The company will furnish supplementally a copy of any omitted schedule or similar attachment to the Securities and Exchange Commission upon request.

49

 

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 sheet of Par Petroleum Corporation and subsidiaries (the "Company") as of December 31, 2013, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the year 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 audit. 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 12% of consolidated total assets as of December 31, 2013, and the Company’s interest in the net loss of Piceance Energy, LLC constitutes 4% of consolidated net loss for the year ended December 31, 2013. 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 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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 audit 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 audit and the report of the other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audit 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, 2013, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 31, 2014

F-1

Report of Independent Registered Public Accounting Firm

To the Members of

Piceance Energy, LLC

Denver, Colorado

We have audited the balance sheet of Piceance Energy, LLC (the “company”) as of December 31, 2013, and the related statements of operations, members’ equity, and cash flows for the year then ended, 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 audit.   

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 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 audit 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, 2013 and the results of its operations and its cash flows for the year then ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

/s/ EKS&H LLLP

EKS&H LLLP

February 28, 2014

Denver, Colorado

F-2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Par Petroleum Corporation

We have audited the accompanying consolidated balance sheet of Par Petroleum Corporation and subsidiaries (the “company”) as of December 31, 2012 (Successor), and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the period from September 1, 2012 through December 31, 2012 (Successor).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 audit.

We conducted our audit in accordance with the standards of the Public company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.The company is not required to have, nor were engaged to perform, an audit of its internal control over financial reporting.Our audit 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 audit provides 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 Par Petroleum Corporation and subsidiaries as of December 31, 2012 (Successor), and the results of their operations and their cash flows for the period from September 1, 2012 through December 31, 2012 (Successor), in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 1 and 2 to the financial statements, the company entered into a plan of reorganization and emerged from bankruptcy on August 31, 2012.As a result of the reorganization, the company applied fresh start accounting and the consolidated financial statements for the period after the reorganization date are presented on a different cost basis than that for the periods before the reorganization and, therefore, are not comparable.

/s/ EKS&H LLLP

EKS&H LLLP

Denver, Colorado

March 27, 2012, except for Note 14, as to which the date is March 31, 2014

F-3

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Delta Petroleum Corporation

We have audited the accompanying consolidated statements of operations, changes in stockholders’ equity and cash flows of Par Petroleum Corporation (formerly Delta Petroleum Corporation) and subsidiaries (the Predecessor) for the period from January 1, 2012 through August 31, 2012.These consolidated financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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 audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Par Petroleum Corporation (formerly Delta Petroleum Corporation) and subsidiaries (the Predecessor) for the period from January 1, 2012 through August 31, 2012, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, the Predecessor filed a petition for reorganization under Chapter 11 of the United States Bankruptcy Code on December 16, 2011. The Predecessor’s plan of reorganization became effective and the Predecessor emerged from bankruptcy protection on August 31, 2012. In connection with its emergence from bankruptcy, the company adopted the guidance for fresh start accounting in conformity with FASB ASC Topic 852, Reorganizations, effective as of August 31, 2012. Accordingly, the company’s consolidated financial statements prior to August 31, 2012 are not comparable to its consolidated financial statements for periods after August 31, 2012.

/s/ KPMG LLP

KPMG LLP

Denver, Colorado

March 27, 2013

F-4

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	December 31, 2013		December 31, 2012
ASSETS
Current assets
Cash and cash equivalents	$	38,061	$	6,185
Restricted cash		802		23,970
Trade accounts receivable		122,913		17,730
Inventories		389,075		10,466
Prepaid and other current assets		7,522		1,575
Total current assets		558,373		59,926
Property and equipment
Property, plant and equipment		107,623		1,415
Proved oil and gas properties, at cost, successful efforts method of accounting		4,949		4,804
Total property and equipment		112,572		6,219
Less accumulated depreciation, depletion and amortization		(3,968)		(373)
Property and equipment, net		108,604		5,846
Long-term assets
Investments in unconsolidated affiliate		101,796		104,434
Intangible assets, net		11,170		8,809
Goodwill		20,603		7,756
Assets held for sale		—		2,800
Other long-term assets		26,539		11
Total assets	$	827,085	$	189,582
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	3,250	$	35,000
Obligations under supply and exchange agreements		390,839		—
Accounts payable		28,870		25,329
Other accrued liabilities		31,956		981
Accrued settlement claims		3,793		8,667
Total current liabilities		458,708		69,977
Long-term liabilities
Long-term debt		94,030		7,391
Derivative liabilities		17,336		10,945
Long-term capital lease obligations		1,526		—
Deferred tax liability		216		—
Contingent consideration liability		11,980		—
Other liabilities		6,473		512
Total liabilities		590,269		88,825
Commitments and contingencies (Note 13)
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, 2013 and 2012, respectively, 30,151,000     shares and 15,008,092 shares issued at December 31, 2013 and 2012,     respectively		301		150
Additional paid-in capital		315,975		109,446
Accumulated deficit		(79,460)		(8,839)
Total stockholders’ equity		236,816		100,757
Total liabilities and stockholders’ equity	$	827,085	$	189,582

See accompanying notes to consolidated financial statements.

F-5

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

	Successor				Predecessor
				September 1		January 1, 2012
	Year Ended			through		through
	December 31, 2013			December 31, 2012		August 31, 2012
Revenues
Refining, distribution and marketing revenues	$	778,126	$	—	$	—
Commodity marketing and logistics revenues		100,149		—		—
Oil and gas sales		7,739		2,144		23,079
Total operating revenues		886,014		2,144		23,079
Operating expenses
Cost of revenues		848,924		—		—
Operating expense, excluding depreciation, depletion     and amortization expense shown separately below		27,251		—		—
Lease operating expense		5,627		1,684		9,038
Transportation expense		—		—		6,963
Production taxes		49		4		979
Exploration expense		—		—		2
Dry hole costs and impairments		—		—		151,347
Depreciation, depletion and amortization		5,982		401		16,041
Trust litigation and settlements		6,206		—		—
General and administrative expense		21,494		4,520		9,386
Acquisition and integration costs		9,794		556		—
Total operating expenses		925,327		7,165		193,756
Operating loss		(39,313)		(5,021)		(170,677)
Other income and (expense):
Interest expense and financing costs, net		(19,471)		(1,056)		(6,852)
Other income		808		86		516
Change in value of common stock warrants		(10,114)		(4,280)
Gain on derivative instruments, net		410		—		—
Loss from unconsolidated affiliates		(2,941)		(1,325)		(20)
Total other expense		(31,308)		(6,575)		(6,356)
Loss before income taxes and reorganization items		(70,621)		(11,596)		(177,033)
Income tax benefit		—		(2,757)		—
Loss before reorganization items		(70,621)		(8,839)		(177,033)
Reorganization items
Professional fees and administrative costs		—		—		22,354
Changes in asset fair values due to fresh start accounting     adjustments		—		—		14,765
Gain on settlement of senior debt		—		—		(166,144)
Gain on settlement of liabilities		—		—		(2,571)
Net loss	$	(70,621)	$	(8,839)	$	(45,437)
Basic loss per common share	$	(3.57)	$	(0.56)	$	(1.57)
Diluted loss per common share	$	(3.57)	$	(0.56)	$	(1.57)
Weighted average number of shares outstanding:
Basic		19,740		15,734		28,841
Diluted		19,740		15,734		28,841

See accompanying notes to consolidated financial statements.

F-6

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

						Additional
		Common Stock				paid-in		Accumulated		Total
	Shares			Amount		capital		Deficit		Equity
Balance, January 1, 2012 (Predecessor)			28,841	$	288	$	1,641,390	$	(1,591,453)	$	50,225
Net loss			—		—		—		(45,437)		(45,437)
Forfeitures			(58)		—		—		—		—
Stock-based compensation			—		—		1,895		—		1,895
Balance, August 31, 2012 (Predecessor)			28,783		288		1,643,285		(1,636,890)		6,683
Cancellation of predecessor common stock			(28,783)		(288)		288		—		—
Elimination of predecessor accumulated deficit			—		—		(1,636,890)		1,636,890		—
Issuance of common stock and fresh start accounting     upon emergence from Chapter 11			14,766		148		102,731		—		102,879
Balance, August 31, 2012 (Successor)			14,766		148		109,414		—		109,562
Stock issued to settle bankruptcy claims			20		—		—		—		—
Stock-based compensation			222		2		32		—		34
Net loss			—		—		—		(8,839)		(8,839)
Balance, December 31, 2012 (Successor)			15,008		150		109,446		(8,839)		100,757
Stock issued in a private transaction, net of offering cost of $830			14,388		144		199,026		—		199,170
Stock issued to settle bankruptcy claims			209		2		2,603		—		2,605
Stock issued through exercise of warrants			184		2		3,739		—		3,741
Stock-based compensation			362		3		1,161		—		1,164
Net loss			—		—		—		(70,621)		(70,621)
Balance, December 31, 2013 (Successor)			30,151	$	301	$	315,975	$	(79,460)	$	236,816

See accompanying notes to consolidated financial statements.

F-7

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Successor				Predecessor
	Year Ended December 31, 2013		September 1 through December 31, 2012		January 1 through August 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(70,621)	$	(8,839)	$	(45,437)
Adjustments to reconcile net loss to cash provided by (used in)      operating activities:
Depreciation, depletion, amortization and accretion		5,982		401		16,041
Non cash interest expense		16,742		1,056		2,989
Change in asset values due to fresh - start accounting     adjustments		—		—		14,765
Gain on extinguishment of senior debt		—		—		(166,144)
Gain on settlement of liabilities		—		—		(2,188)
(Gain) loss on property sales		(50)		(82)		126
Dry hole costs and impairments		—		—		151,347
Stock-based compensation		1,161		34		1,895
Change in value of common stock warrants		10,114		4,280		—
Loss from unconsolidated affiliates		2,941		1,325		20
Deferred income tax expense (benefit)		179		(2,757)		—
Other		—		—		(699)
Net changes in operating assets and liabilities:
Trade accounts receivable		(45,698)		(2,234)		3,472
Prepaids and other current assets		(2,569)		(538)		(1,378)
Inventories		40,141		—		—
Accounts payable		15,829		2,718		(4,187)
Supply and exchange agreements		(13,061)		—		—
Settlement liability		1,898		—		—
Accrued reorganization costs		—		—		9,116
Other accrued liabilities		1,335		—		—
Net cash used in operating activities		(35,677)		(4,636)		(20,262)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(7,768)		—		(1,613)
Acquisitions, net of cash acquired		(559,279)		(17,439)		—
Proceeds from asset sales		2,850		—		74,209
Proceeds from sale of other fixed assets		—		39		26
Capitalized drilling costs paid to operator		(303)		(415)		—
Proceeds from sale of unconsolidated affiliates		—		125		—
Net cash (used in) provided by investing activities		(564,500)		(17,690)		72,622
CASH FLOWS FROM FINANCING ACTIVITIES:
Funding of purchase of HIE from supply and exchange      agreements		378,238		—		—
Proceeds from sale of common stock, net of offering costs		199,170		—		—
Proceeds from exercise of common stock warrants		18		—		—
Proceeds from borrowings		159,800		35,000		23,000
Repayments of borrowings		(121,909)		—		(59,535)
Payment of deferred loan costs		(2,264)		—		—
Fund distribution agent account		—		—		(21,805)
Proceeds from (funding of) Wapiti and General Recovery      Trusts		—		2,446		(2,000)
Recoveries from bankruptcy settlements		—		5,183		—
Restricted cash released from (held to) secure letter of credits		19,000		(19,000)		—
Net cash provided by (used in) financing activities		632,053		23,629		(60,340)
Net increase (decrease) in cash and cash equivalents		31,876		1,303		(7,980)
Cash at beginning of period		6,185		4,882		12,862
Cash at end of period	$	38,061	$	6,185	$	4,882
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest and financing costs	$	2,186	$	—	$	3,745
NON-CASH INVESTING AND FINANCING ACTIVITIES
Stock issued used to settle bankruptcy claims	$	2,605	$	—	$	—
Interest payable capitalized to principal balance	$	6,096	$	—	$	—
Non-cash additions to property, plant and equipment	$	—	$	209	$	—

See accompanying notes to consolidated financial statements.

F-8

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements 

Note 1 - Overview

We are a diversified energy holding company based in Houston, Texas (OTCQB:PARR). We were created through the successful reorganization of Delta Petroleum in August 2012. The reorganization converted approximately $265 million of unsecured debt to equity and allowed us to preserve significant tax attributes. Currently, we operate in three segments: (i) refining, distribution and marketing, (ii) natural gas and oil operations and (iii) commodity marketing and logistics operations.

 Our refining, distribution and marketing segment consists of a refinery in Kapolei, Hawaii. The refinery produces ultra-low sulfur diesel, gasoline, jet fuel, marine fuel and other associated refined products primarily for consumption in Hawaii. Our refinery logistics assets include refined products terminals, pipelines, a single point mooring and other associated logistics assets. In addition, we distribute products though 31 branded retail outlets located across the islands of Oahu, Maui and Hawaii. The refining, distribution and marketing segment was established through the acquisition of Hawaii Independent Energy, LLC (“HIE”) (formerly known as Tesoro Hawaii, LLC (“Tesoro Hawaii”)) in September 2013 for approximately $75 million in cash, plus net working capital and inventories and certain contingent earn out payments of up to approximately $40 million (the “HIE Acquisition”).  As part of the purchase price, we also funded$24.3million of start-up expenses and for a major overhaul of a co-generation turbine used at the refinery prior to closing.  

Our natural gas and oil operations consist primarily of a 33.34% interest in Piceance Energy, LLC (“Piceance Energy”) (Note 3 - Investment in Piceance Energy). Piceance Energy is a joint venture with Laramie Energy II, LLC (“Laramie”), who owns the remaining interest and manages the day to day operations of the joint venture. Laramie is a Denver-based company primarily focused on finding and developing natural gas reserves from unconventional gas reservoirs within the Rocky Mountain region. Piceance Energy was formed and capitalized in August 2012 when we and Laramie Energy contributed oil and natural gas assets, surface real estate, and other related assets located in the Piceance Basin geological province of Colorado to the joint venture entity.

Our commodity marketing and logistics segment focuses on sourcing, marketing, transportation and distribution of crude oil and refined products. Our logistics capability consists of historical pipeline shipping status, a rail car 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, the Gulf Coast, and the East Coast regions of the U.S. The commodity marketing and logistics operations segment was established through the acquisition of Texadian Energy, Inc. (“Texadian”) (formerly known as SEACOR Energy, Inc.) in December 2012 for approximately $14 million in cash, plus approximately $3 million in working capital.

As a result of these transactions, our results of operations for any period after December 31, 2013 will not be comparable to any prior period.

On January 23, 2014, we amended and restated 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. 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 outstanding prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis, unless otherwise noted. No adjustments have been made to the share or per share amounts of our Predecessor (see Note 20 - Subsequent Events).

To generate earnings and cash flows from operations, the Company’s refining, distribution and marketing segment is primarily dependent upon processing crude oil and selling refined petroleum products at margins sufficient to cover fixed and variable costs and other expenses. Crude oil and refined petroleum products are commodities and factors largely out of the Company’s control can cause prices to vary over time.

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 consolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. We do not have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

Our wholly-owned subsidiaries include Hawaii Pacific Energy, LLC (“Hawaii Pacific Energy”)  which acquired all of the outstanding membership interests of HIE on September 25, 2013 (see Note 4– Acquisitions and Dispositions), Par Piceance Energy, LLC, which owns our investment in Piceance Energy (see Note 3 – Investment in Piceance Energy) and Texadian, which we acquired on December 31, 2012 (see Note 4 – Acquisitions and Dispositions). Certain amounts from prior periods have been reclassified to conform to the current presentation.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include fair value of assets and liabilities recorded in connection with the application of fresh-start reporting or acquisitions, natural gas and oil reserves, depletion and impairment of natural gas and oil properties, income taxes and the valuation allowances related to deferred tax assets, bad debts, derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.

F-9

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

 

Fresh-Start Reporting and the Effects of the Plan

Certain companies qualify for fresh-start reporting in connection with their emergence from bankruptcy. Fresh-start reporting is appropriate on the emergence from bankruptcy if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. We met these requirements on August 31, 2012 and adopted fresh-start reporting resulting in the creation of a new reporting entity.

The bankruptcy court issued a confirmation order approving our plan of reorganization (the “Plan”) on August 15, 2012 and we met the requirements of the Plan on August 31, 2012. Under the requirements of fresh-start reporting, we have adjusted our assets and liabilities to their estimated fair values as of August 31, 2012 in conformity with the guidance for the acquisition method of accounting for business combinations. The net effect of all fresh-start adjustments, including the effects of implementing the plan, resulted in a gain of approximately $154 million, which is reflected in the 2012 Predecessor Period. The application of the fresh-start reporting provisions created a new reporting entity having no retained earnings nor accumulated deficit.

Our fresh-start adjustments consisted primarily of (i) estimates of the fair value of our minority interest in Piceance Energy and (ii) of the fair value of our remaining existing fixed assets and liabilities. A description of the adjustments and amounts is provided in Note 19 – Reorganization under Chapter 11, Fresh-Start Reporting and the Effects of the Plan.

 

Cash and Cash Equivalents

Cash and cash equivalents consist of demand deposits and funds invested in highly liquid short-term investments with original maturities of three months or less.

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.

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 collectability and establish or adjust our allowance as necessary using the specific identification method.As of December 31, 2013 and 2012, we had no significant allowance for doubtful accounts. 

Refined Product Exchanges

We enter into exchange and supply contracts whereby we agree to deliver a particular quantity and quality of refined products at a specified location and date to a particular counterparty and to receive from the same counterparty a particular quantity and quality of refined products at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions with the exception of associated grade or location differentials that are settled in cash each month. These transactions are not recorded as revenue because they involve the exchange of refined product inventories held for sale in the ordinary course of business to facilitate sales to customers. The exchange transactions are recognized at the carrying amount of the inventory transferred plus or minus any cash settlement due to grade or location differentials.

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.

HIE 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 HIE’s storage tanks governed by a storage agreement. Legal title to the crude oil passes to HIE at the tank outlet. After processing, Barclays takes title to the refined products when the refined products enter the tanks which are then stored in HIE’s storage tanks until sold to HIE’s 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.

Investment in Unconsolidated Affiliate

We account for our investment in unconsolidated affiliate using the equity method as we have the ability to exert significant influence, but do not control the operating and financial policies. Our proportionate share of net income (loss) of these entities is recorded as income (loss) from unconsolidated affiliates in the consolidated statements of operations. Investment in unconsolidated affiliate is reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

F-10

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

 

At December 31, 2013 and 2012, our investment in unconsolidated affiliates consisted of our ownership interest in Piceance Energy (see Note 3 - Investment in Piceance Energy.)

Property, Plant and Equipment (Other than Natural Gas and Oil Properties)

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
Logistic	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 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 with significant acquisition costs 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 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.

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. 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.

F-11

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

 

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 or when circumstances indicate that impairment may exist. 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.

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, distribution and marketing business’ refinery and 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 depreciation, depletion and amortization expense 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 statements of consolidated 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 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.

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 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 it will not net settle.  Should we not designate a contract as a normal purchase or normal sale then 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, 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. As of December 31, 2012, we did not elect this exemption for our open contracts which were settled in the first quarter of 2013.

 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.

F-12

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

 

As a part of the Plan of Reorganization, we issued warrants (see Note 10 - Debt) 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 reported in change in value of common stock warrants and loss on derivative instruments, net respectively, on our consolidated statement of operations.

Accrued Settlement Claims

We accrued an estimate of the settlement liability relating to claims resulting from our bankruptcy (See Note 13 - Commitments and Contingencies). Professional fees relating to the settlement of bankruptcy claims are charged to earnings in the period incurred.

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 2010, 2011, and 2012. 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 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. These transactions include sale and purchase transactions entered into with the same counterparty that are deemed to be in contemplation with one another.

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, 2013 and 2012, 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 rail cars. 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.

Refining, Distribution and Marketing. 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 statements of consolidated operations, while the related transportation costs are included in cost of sales. Federal excise and state motor fuel taxes, which are remitted to governmental agencies through our refining segment and collected from customers in our retail segment, are included in both revenues and cost of sales in our statements of consolidated operations.

F-13

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

 

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 (see Note 16 - Loss Per Share). 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 our functional currency (“U.S. $”). 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) in the accompanying consolidated statement of operations in the period in which the currency exchange rates change.  

Note 3 - Investment in Piceance Energy

We account for our 33.34% ownership interest in Piceance Energy using the equity method of accounting because we are able to exert significant influence but do not control the operating and financial policies. The Piceance Energy LLC Agreement provides that its sole manager may make a written capital call such that each member shall make additional capital contributions up to an aggregate combined total capital contribution of $60 million ($20 million to our interest), if approved by a majority of its board. If any member does not fund its share of the capital call, its interest may be reduced or diluted by the amount of the shortfall. In addition, Piceance Energy has a $400 million secured revolving credit facility secured by a lien on its natural gas and oil properties and related assets with a borrowing base currently set at $120 million.  As of December 31, 2013, the balance outstanding on the revolving credit facility was approximately $90.2 million. We are guarantors of Piceance Energy’s credit facility, with recourse limited to the pledge of our equity interests of Par Piceance Energy. Under the terms of its credit facility, Piceance Energy is generally prohibited from making future cash distributions to its owners, including us.

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

			September 1
	Year Ended		through
	December 31, 2013		December 31, 2012
Beginning balance	$	104,434	$	105,344
Loss from unconsolidated affiliates		(3,516)		(1,325)
Accretion of basis difference		575		—
Capitalized drilling costs obligation paid		303		415
Ending balance	$	101,796	$	104,434

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

	December 31, 2013		December 31, 2012
Assets
Current assets	$	5,901	$	6,275
Non-current assets		454,402		460,991
Current liabilities		(13,040)		(11,826)
Non-current liabilities		(96,738)		(94,369)

	Year Ended		September 1 through
	December 31, 2013		December 31, 2012
	100%		100%
Oil, natural gas and natural gas liquids     revenues	$	61,091	$	19,391
Loss from operations		(6,765)		(2,095)
Net loss		(10,546)		(3,975)

The net loss for the year ended December 31, 2013 includes $26.6 million and $770 thousand in DD&A expense and losses on derivative instruments, respectively. The net loss for the period from September 1 through December 31, 2012 include $8.5 million and $917 thousand of DD&A expense and losses on derivative instruments, respectively.

At December 31, 2013 and 2012, our equity in the underlying net assets of Piceance Energy exceeded the carrying value of our investment by approximately $15.1million and $15.9 million, respectively. This difference arose due to lack of control and marketability discounts and we attributed it to natural gas and oil properties and will amortize the difference over 15 years based on the estimate of proved reserves at the date Piceance Energy was formed.

 

F-14

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

 

Note 4 – Acquisitions and Dispositions

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.

Texadian Energy, Inc.

On December 31, 2012, we acquired Texadian, an indirect wholly-owned subsidiary of SEACOR Holdings Inc., for $14 million plus estimated net working capital of approximately $3 million at closing resulting in approximately $17 million of cash paid at closing. Texadian operates an oil transportation, distribution and marketing business with significant logistics capabilities. The purchase price for the acquisition was funded with a combination of cash and additional borrowings under the Tranche B Loan (see Note 10 - Debt). During 2013, the purchase price was reduced by $1.3 million due to funds received from SEACOR Holdings, Inc. for certain employee-related benefits.

The purchase was accounted for as a business combination whereby the purchase price is 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 Texadian’s, and specifically 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. These include relationships with suppliers and shippers and favorable railcar leases. These intangible assets will be amortized over their estimated useful lives on a straight line basis, which approximates their consumptive life.

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

Intangible assets	$	8,809
Goodwill		6,990
Net non cash-working capital		3,097
Deferred tax liabilities		(2,757)
Total, net of cash acquired	$	16,139

None of the goodwill or intangible assets are expected to be deductible for income tax reporting purposes. Acquisition costs of approximately $556 thousand are included in our consolidated statements of operations for the period ended December 31, 2012.

Hawaii Independent Energy, LLC

On June 17, 2013 (the “Execution Date”), our wholly-owned subsidiary, Hawaii Pacific Energy, entered into a membership interest purchase agreement (the “HIE Purchase Agreement”) with Tesoro Corporation, (the “Seller”) and solely for the purpose set forth in the HIE Purchase Agreement, Tesoro Hawaii. Pursuant to the HIE Purchase Agreement, on September 25, 2013 (the “Effective Date”), Hawaii Pacific Energy purchased from the Seller all of the issued and outstanding units representing the membership interests in Tesoro Hawaii (the “Purchased Units”), and indirectly thereby also acquired Tesoro Hawaii’s wholly-owned subsidiary, Smiley’s Super Service, Inc. Tesoro Hawaii owns and operates (i) a petroleum refinery located at the Campbell Industrial Park in Kapolei, Hawaii (the “Refinery”), (ii) certain pipeline assets, floating pipeline mooring equipment, and refined products terminals, and (iii) 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”).

Hawaii Pacific Energy acquired the Purchased Units for $75 million, paid in cash at the closing of the HIE Purchase Agreement, plus net working capital and inventories at closing and 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 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 in the event Hawaii Pacific Energy disposes of any facility used in the acquired business, Hawaii Pacific Energy's obligation to make earnout payments could be modified and/or accelerated as provided in the HIE Purchase Agreement. The purchase price was paid with a portion of the net proceeds from the sale of the shares of our common stock in a private transaction (see Note 14 - Stockholders’ Equity), amounts received pursuant to the Supply and Exchange Agreements (see Note 9 - Supply and Exchange Agreements) and the ABL Facility (see Note 10 - Debt).

F-15

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

 

We accounted for the acquisition of HIE as a business combination whereby the purchase price has been preliminary 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. These include 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.

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

Inventory	$	418,750
Trade accounts receivable		59,485
Prepaids and other current assets		1,978
Property, plant and equipment		58,782
Land		39,800
Goodwill		13,613
Intangible assets		4,689
Accounts payable and other current liabilities		(18,154)
Contingent consideration liability		(11,980)
Other noncurrent liabilities		(6,384)
Total	$	560,579

We are continuing to evaluate certain liabilities assumed in the acquisition, including those related to employee benefits. We have recorded a preliminary estimate of the liability and expect to finalize the purchase price allocation during 2014.

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

Pro Forma Effects of the Acquisitions

The unaudited pro forma financial information presented below assumes that the Texadian and HIE acquisitions occurred as of January 1, 2012 and combines the Predecessor and Successor periods to include a full year of results for the year ended December 31, 2012.We did not include any adjustments related to the application of fresh-start reporting for the year ended December 31, 2012. 

	2013		2012
(in millions)
Revenues	$	2,986.8	$	3,811.1
Net loss	$	(113.6)	$	(12.0)

Revenue and earnings for HIE subsequent to the acquisition are included in Note 17 - Segment Information. 

Assets Contributed to Piceance Energy

At December 31, 2011, Delta’s oil and gas assets were classified as held for use and no impairment charges resulted from the analysis performed at December 31, 2011 as the estimated undiscounted net cash flows exceeded carrying amounts for all properties. In August 2012, the Bankruptcy Court approved a plan of sale of substantially all of the Predecessor’s assets and accordingly these assets were classified as held for sale and an impairment of approximately $151.3 million was recognized for the period from January 1, 2012 through August 31, 2012 to write-down these assets to fair value due to the application of fresh-start reporting. Theassets were then contributed to Piceance Energy in accordance with our Plan of Reorganization.

Assets Held for Sale

As of December 31, 2012, we classified certain compressors as held for sale, which were recorded at the lower of cost or estimated net realizable value. On February 20, 2013, these compressors were sold for approximately $2.9 million resulting in a gain of $50thousand.

F-16

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

Note 5 – Property, Plant and Equipment

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

	December 31,
	2013		2012
Land	$	39,800	$	—
Buildings and equipment		65,878		—
Other		1,945		1,415
Property, plant and equipment		107,623		1,415
Proved oil and gas properties		4,949		4,804
Less: accumulated depreciation, depletion     and amortization		(3,968)		(373)
	$	108,604	$	5,846

Note 6 – Asset Retirement Obligations

The following is a reconciliation of our AROs (in thousands):

	Successor				Predecessor
			September 1		January 1
	Year Ended		through		through
	December 31, 2013		December 31, 2012		August 31, 2012
Asset retirement obligation –     beginning of period	$	512	$	476	$	3,799
Obligation acquired		2,601		—		—
Accretion expense		59		36		178
Change in estimate		—		—		437
Settlement upon transfer to     Piceance Energy		—		—		(3,938)
Asset retirement obligation –     end of period	$	3,172	$	512	$	476

As the result of the contribution of assets to Piceance Energy during the reorganization, approximately $3.9 million of our AROs was deemed settled as of the Emergence Date.

Note 7 - Inventories

The following is a summary of our inventory (in thousands):

								December 31,
	December 31, 2013							2012
				Supply and
		Titled		Exchange
		Inventory		Agreements		Total		Titled Inventory
Crude oil and feedstocks	$	—	$	146,158	$	146,158	$	10,466
Refined products and blend stock		67,532		161,554		229,086		—
Spare parts, materials and supplies, and merchandise		13,831		—		13,831		—
	$	81,363	$	307,712	$	389,075	$	10,466

F-17

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

Note 8 – Intangible assets

Our intangible assets consist of the following (in thousands):

	December 31,
	2013		2012
Amortized intangible assets:
Gross carrying amount:
Supplier relationships	$	3,360	$	3,360
Rail car leases		3,249		3,249
Historical shipper status		2,200		2,200
Trade names and trademarks		4,689		—
Subtotal		13,498		8,809
Accumulated amortization
Supplier relationships		(258)		—
Rail car leases		(650)		—
Historical shipper status		(1,100)		—
Trade name and trademarks		(320)		—
Subtotal		(2,328)		—
Net:
Supplier relationships		3,102		3,360
Rail car leases		2,599		3,249
Historical shipper status		1,100		2,200
Trade name and trademarks		4,369		—
Total amortized intangible assets, net	$	11,170	$	8,809

Amortization expense was approximately $2.3 million for the year ended December 31, 2013. There was no amortization expense during 2012. Expected future amortization expense for each of the next five years and thereafter is as follows (in thousands):

Year Ended	Amount
2014	$	3,571
2015		2,471
2016		2,151
2017		908
2018		258
Thereafter		1,811
	$	11,170

During the year ended December 31, 2013 the changes in the carrying amount of goodwill for the year ended December 31, 2013 were as follows (in thousands):

Balance at beginning of period	$	7,756
Additions		13,613
Texadian purchase price adjustments		(766)
Balance at end of period	$	20,603

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. We entered into the Supply and Exchange Agreements 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.Additionally, Barclays 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 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 volumes at period-end in excess of the Block Volume, we record a liability for the Block Volume valued at the per barrel carrying value of the refined product inventory owned by Barclays.From time to time, we may sell refined product inventory that causes our refined product inventory to be less than the Block Volume.To the extent of this shortfall, we record a liability for the volumes that we would need to purchase at current market prices in order to meet the Block Volume requirement. The liability related to the Supply and Exchange Agreements is included in obligations under supply and exchange agreements on our consolidated balance sheet.

For the year ended December 31, 2013, we incurred approximately $3.7 million in handling fees related to the Supply and Exchange Agreements, which is included in cost of revenues on our consolidated statement of operations. For the year ended December 31, 2013, interest expense and financing costs, net includes $1.4 million of expense related to the Supply and Exchange Agreements.

F-18

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

 

Note 10 - Debt

Our debt is as follows (in thousands):

	December 31,
	2013		2012
Tranche B Loan	$	19,480	$	35,000
Delayed Draw Term Loan Agreement		—		13,465
ABL Facility		51,800		—
Retail Credit Agreement		26,000		—
Less: unamortized debt discount – warrants		—		(6,014)
Less: unamortized debt discount – embedded derivative		—		(60)
Total debt, net of unamortized debt discount		97,280		42,391
Less: current maturities		(3,250)		(35,000)
Long-term debt, net of current maturities and unamortized discount	$	94,030	$	7,391

Annual maturities of our long-term debt are due during the following years (in thousands):

Year		Amount Due
2014	$	3,250
2015		2,600
2016		22,080
2017		54,400
2018		2,600
Thereafter		12,350
	$	97,280

Delayed Draw Term Loan Credit Agreement

Pursuant to the Plan, on the Emergence Date, we and certain of our subsidiaries (the “Guarantors” and, together with the company, the “Loan Parties”) entered into a Delayed Draw Term Loan Credit Agreement (the “Loan Agreement”) with Jefferies Finance LLC, as administrative agent (the “Agent”) for the lenders party thereto from time to time, including WB Delta, Ltd., Waterstone Offshore ER Fund, Ltd., Prime Capital Master SPC, GOT WAT MAC Segregated Portfolio, Waterstone Market Neutral MAC51, Ltd., Waterstone Market Neutral Master Fund, Ltd., Waterstone MF Fund, Ltd., Nomura Waterstone Market Neutral Fund, ZCOF Par Petroleum Holdings, L.L.C. and Highbridge International, LLC (collectively, the “Lenders”), pursuant to which the Lenders agreed to extend credit to us in the form of term loans (each, a “Loan” and collectively, the “Loans”) of up to $30 million. We borrowed $13 million on the Emergence Date in order to, along with the proceeds from the Contribution Agreement: (i) repay the loans and obligations due under the Predecessor’s secured debtor-in-possession credit facility, and (ii) pay allowed but unpaid administrative expenses to the Debtors related to the Plan. During 2013, we borrowed an additional $17 million for general corporate use.  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. Included in interest expense and financing cost, net on the consolidated statements of operations is $6.1 million recorded as loss on extinguishment of debt related to the November 2013 repayment.

Amendment to the Loan Agreement

On December 28, 2012, in order to fund a portion of the purchase price for our acquisition of Texadian Energy, the Loan Parties entered into an amendment to the Loan Agreement with the Agent and the Lenders, pursuant to which certain lenders (the “Tranche B Lenders”) agreed to extend additional borrowings to us (the “Tranche B Loan”). The total commitment of the Tranche B Loan of $35 million was drawn at closing. In addition to funding a portion of the purchase price of the acquisition of Texadian, the Tranche B Loan provided cash collateral for our former cash collateralizedletter of credit facility. Pursuant to the Eighth Amendment to the Loan Agreement entered into on June 24, 2013, the Lenders refinanced and replaced the Tranche B Loan with new Tranche B Loans in the aggregate principal amount of $65 million (the “New Tranche B Loans”). The proceeds from the New Tranche B Loans were applied to prepay in full the Tranche B Loan, to make payments due under the membership interests purchase agreement in connection with the acquisition of HIE (the “HIE Purchase Agreement”), and for working capital and general corporate purposes.

F-19

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

 

On September 25, 2013 and in connection with the acquisition of HIE, we entered into a Tenth Amendment to the Loan Agreement pursuant to which the Lenders (i) consented to the consummation of the transactions contemplated by the HIE Purchase Agreement and the use of a portion of the proceeds from the Private Placement to fund a portion of the consideration for the acquisition of HIE and for certain other purposes, (ii) provided certain other consents in connection with the transactions contemplated by the HIE Purchase Agreement, (iii) increased the interest rate applicable to certain of the loans, and (iv) amended certain provisions of the Loan Agreement and the other loan documents in connection with the consummation of the transactions contemplated by the HIE Purchase Agreement and the Private Placement (see Note 14 – Stockholder’s Equity).  

The consent provided by the Lenders was conditioned on, among other things, (i) the repayment in full of the New Tranche B Loans owing to all Lenders except for ZCOF Par Petroleum Holdings, L.L.C., and a partial repayment of the New Tranche B Loans owing to ZCOF Par Petroleum Holdings, L.L.C. from a portion of the proceeds from the Private Placement and (ii) a portion of the proceeds from the Private Placement being used to consummate the transactions contemplated by the HIE Purchase Agreement.  

The New Tranche B Loans bear interest (a) from June 24, 2013 through October 31, 2013 at a rate equal to 9.75% per annum payable, at the election of the company, either (i) in cash or (ii) in kind, and (b) from and after November 1, 2013, at a rate equal to 14.75% per annum payable either (i) in cash or (ii) in kind. Additionally, we agreed to pay the New Tranche B Lenders a nonrefundable exit fee equal to 2.5% of the aggregate amount of the New Tranche B Loans. The exit fee is earned in full and payable on the maturity date of the Tranche B Loans or, if earlier, the date on which the New Tranche B Loans are paid in full.  

The New Tranche B Loans mature and are payable in full on August 31, 2016.We may prepay the New Tranche B Loans at any time, provided that any prepayment is in an integral multiple of $100,000 and not less than $100,000 or, if less, the outstanding principal amount of the New Tranche B Loans. Amounts to be applied to prepayment of New Tranche B Loans shall be applied (i) first, towards payment of interest then outstanding and fees then due, and (ii) second, towards payment of principal then outstanding.

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.

ABL Facility

On September 25, 2013 and in connection with the with the acquisition of HIE, HIE and its subsidiary (the “ABL Borrowers”) and Hawaii Pacific Energy entered into an asset-based revolving credit facility (the “ABL Facility”) to provide the ABL Borrowers with a senior secured revolving credit facility of up to $125.0 million under which the ABL Borrowers may borrow amounts from time to time based on the available borrowing base as determined in accordance with the ABL Facility. The ABL Facility also allows the ABL Borrowers to use up to $50 million of availability under the ABL Facility for the issuances of letters of credit. The ABL Borrowers borrowed $15 million on September 25, 2013 under the ABL Facility in order to, in part, (i) fund the purchase price under the Purchase Agreement, and (ii) provide working capital to the ABL Borrowers. The proceeds from any future amounts borrowed pursuant to the ABL Facility will be used for general corporate purposes and to fund the working capital of the ABL Borrowers. As of December 31, 2013, the total capacity of the ABL Facility was $83.3 million.

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 LIBO rate specified below (“LIBO Rate”) 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 LIBO Rate 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 LIBO Rate for a LIBO Rate loan denominated in dollars with a one-month interest period commencing on such day plus 1.00%. The effective weighted-average interest rate for 2013 was 3.13%. 

The amounts borrowed pursuant the ABL Facility and all obligations arising under the ABL Facility are secured by a lien in favor of the ABL Agent on substantially all of HIE’s assets.

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 LIBO Rate loans, a facing fee and customary administrative fees.

F-20

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

 

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

The ABL Facility requires HIE and its subsidiaries and Hawaii Pacific Energy to comply with various affirmative and negative covenants affecting its business and operations, including compliance by HIE in certain circumstances with a minimum ratio of consolidated earnings before interest, taxes, depreciation and amortization (“EBITDA”), as adjusted, to total fixed charges of 1.0 to 1.0.

HIE Retail Credit Agreement

On November 14, 2013 , HIE Retail, LLC (“HIE Retail”), our subsidiary, entered into a Credit Agreement (the “Retail Credit Agreement”) in the form of a senior secured term loan of up to $30 million the (“Term Loan”) and a senior secured revolving line of credit of up to $5 million (the “Revolver”). HIE Retail initially borrowed $26 million of the Term Loan at the closing and an additional $4 million of the Term Loan upon HIE Retail’s compliance with certain liquor licensing requirements, if such requirements are satisfied prior to December 31, 2014, will be available. The proceeds of the Term Loan are available for general corporate purposes.

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) as follows:

 

Period (during and as of the last day of)	Maximum Leverage Ratio
2013 Fiscal Year	5.75 to 1.00
2014 Fiscal Year	5.50 to 1.00
2015 Fiscal Year	5.25 to 1.00
2016 Fiscal Year	5.00 to 1.00
2017 Fiscal Year, and at all times thereafter	4.75 to 1.00

HIE Retail is also required to maintain a Fixed Charge Coverage Ratio of 1.15:1.00.

Term Loan

Principal on the Term Loan will be repaid in 28 quarterly principal payments over the term through November 14, 2020.

The Term Loan will bear 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. The effective interest rate for 2013 on the outstanding loan was 2.5%.

Interest is payable at the end of the selected interest period, but no less frequently than quarterly. 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	%	0	%
2	4.00x-5.00x	2.25	%	..25	%
3	>5.00x	2.5	%	..50	%

Initial pricing from the Effective Date until March 31, 2014 was set at Level 2.

F-21

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

  

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.

Revolver

The Revolver matures on November 14, 2016. Letters of credit issued under the Revolver are not to expire beyond the maturity date of the Revolver.

Advances under the 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 (the “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 commencing on the November 14, 2013.

The 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	..25	%	1.75	%	-.25	%
2	4.00x-5.00x	..375	%	2.00	%	0	%
3	>5.00x	..50	%	2.25	%	..25	%

Initial pricing from the Effective Date until March 31, 2014 was set at Level 2.

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. Fees for the issuance and negotiation of Commercial Letters of Credit will be based on the Agent’s standard fee schedule then in effect.

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, 2013, we had $41.6 million of letters of credit outstanding related to this agreement.

Letter of Credit Facility

 On December 27, 2012, we entered into a letter of credit facility agreement (the “Letter of Credit Facility”). The Letter of Credit Facility provided for a letter of credit facility in an aggregate principal amount of $30 million that was available for the issuance of cash-collateralized standby letters of credit for us or any of our subsidiaries.

 In connection with the acquisition of Texadian, we issued an Irrevocable Standby Letter of Credit in favor of SEACOR Holdings, Inc. in the amount of $11.7 million (the “Irrevocable Standby Letter of Credit”). The Irrevocable Standby Letter of Credit secured SEACOR Holdings, Inc. in the event that certain letters of credit were drawn. Those letters of credit have been terminated and released. The Letter of Credit Facility was terminated on June 17, 2013.

F-22

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements 

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, 2013, we are in compliance with all of our credit agreements.  

Warrant Issuance Agreement

Pursuant to the Plan of Reorganization, on the Emergence Date, we issued to the Lenders warrants (the “Warrants”) to purchase up to an aggregate of 959,213 shares of our common stock (the “Warrant Shares”). In connection with the issuance of the Warrants, we also entered into a Warrant Issuance Agreement, dated as of the Emergence Date (the “Warrant Issuance Agreement”). Subject to the terms of the Warrant Issuance Agreement, the holders are entitled to purchase shares of common stock upon exercise of the Warrants at an exercise price of $0.10 per share of common stock (the “Exercise Price”), subject to certain adjustments from time to time as provided in the Warrant Issuance Agreement. The Warrants expire on the earlier of (i) August 31, 2022 or (ii) the occurrence of certain merger or consolidation transactions specified in the Warrant Issuance Agreement. A holder may exercise the Warrants by paying the applicable exercise price in cash or on a cashless basis.

The number of shares of our common stock issuable upon exercise of the Warrants and the exercise prices of the Warrants will be adjusted in connection with certain issuances or sales of shares of the company’s common stock and convertible securities, or any subdivision, reclassification or combinations of common stock. Additionally, in the case of any reclassification or capital reorganization of the capital stock of the company, the holder of each Warrant outstanding immediately prior to the occurrence of such reclassification or reorganization shall have the right to receive upon exercise of the applicable Warrant, the kind and amount of stock, other securities, cash or other property that such holder would have received if such Warrant had been exercised.

From the Emergence Date through December 31, 2013, we issued an additional 228,735 shares of our common stock to settle bankruptcy matters. This entitled the Lenders to receive an additional 14,859 Warrant Shares through December 31, 2013. On December 12, 2013, Warrants to purchase 183,389 Warrant Shares were exercised.At December 31, 2013, Warrants to purchase an aggregate of 790,683 Warrant Shares were outstanding.

Based on certain anti-dilution provisions in the Warrant Issuance Agreement, we have concluded that the Warrants are not indexed to our equity. Accordingly, on the Emergence Date we estimated the fair value of the Warrants on the date of grant to be approximately $6.6 million and recorded the estimated fair value of the Warrants as a derivative liability with the offset to debt discount. The debt discount was being amortized over the life of the Loan Agreement, using the effective interest method until repayment of the delayed draw term loan in November 2013. Subsequent changes in the fair value of the Warrants are reflected in earnings (see Note 11 – Fair Value Measurements).  

Note 11 - 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 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 the valuation techniques discussed below 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.

F-23

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Fresh-Start Reporting –  The fair value of the Successor was based on its estimated enterprise value post-bankruptcy using valuation techniques described in notes (a) through (e) below. The individual components consist of the estimated enterprise value of Piceance Energy and the sum of the estimated fair value of the assets we retained. The estimates of fair value of the net assets were reflected in the Successor’s consolidated balance sheet as of August 31, 2012.

	Fair Value at		Fair Value
	August 31, 2012		Technique
	(in thousands)
Oil and gas properties
Proved	$	4,587	(a)(b)
Other assets
Frac tanks		1,400	(c)
Compressors		2,800	(c)
Miscellaneous		39	(d)
Investment in Piceance Energy		105,344	(e)

(a) Certain proved property was valued using the cost valuation technique. A significant input in this measurement was the estimated cost of the properties. A change in that estimated cost would be directly correlated to change in the estimated fair value of the property. We consider this to be a Level 3 fair value measurement.

(b) The estimated fair value of our Point Arguello Unit offshore California was valued using a market valuation technique based on standalone bids received by third-parties during the sale process. We consider this to be a Level 2 fair value measurement.

(c) The estimated fair value of our frac tanks and compressor units was valued using a market valuation technique which was based on published listings of similar equipment or standalone bids received by third-parties. We consider these to be Level 2 fair value measurements.

(d) Miscellaneous assets (assets that we were unable to value using the income or market valuation techniques) were valued using the cost valuation technique. We consider this to be a Level 3 fair value measurement.

(e) The estimated fair value of our investment in Piceance Energy was based on its enterprise value and uses various valuation techniques including (i) an income approach based on proved developed reserves’ future net income discounted back to net present value based on the weighted average cost of capital for comparable independent oil and natural gas producers, and (ii) a market multiple approach. Proved property was valued using the income approach. A discounted cash flow model was prepared based off of an independent reserve report with a discount rate of 10% applied to proved developed producing reserves, 15% to proved developed non-producing reserves and 20% to proved undeveloped reserves. The prices for oil and natural gas were forecasted based on NYMEX strip pricing adjusted for basis differentials. For the market multiple approach, we reviewed the transaction values of recent similar asset transactions and compared the purchase price per Mcfe of proved developed reserves and purchase price per Mcfe per day of net equivalent production of those transactions to the independent reserve report. Unproved acreage was valued using a cost approach based on recent sales of acreage in the area. Based on these valuations, the equity value of our 33.34% interest in Piceance Energy was estimated to be approximately $105.3 million on the Emergence date. We consider this to be a Level 3 fair value measurement.

Purchase Price Allocation of Texadian – The fair values of the assets acquired and liabilities assumed as a result of the Texadian acquisition were estimated as of the date of the acquisition using valuation techniques described in notes (a) through (f) described below.

	Fair Value at		Fair Value
	December 31, 2012		Technique
	(in thousands)
Net non-cash working capital	$	3,631	(a)
Supplier relationship		3,360	(b)
Historical shipper status		2,200	(c)
Railcar leases		3,249	(d)
Goodwill		7,756	(e)
Deferred tax liabilities		(2,757)	(f)
	$	17,439

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

(b) The estimated fair value of the supplier relationship was estimated using a form of the income approach, the Multiple-Period Excess Earnings Method. Significant inputs used in this model include estimated cash flows from the suppliers, customer growth and rates and a discount rate. An increase in the cash flows attributable to the supplier relationships would result in an increase in the value of such relationship, while an increase in the discount rate would result in a decrease in the value. We consider this to be a Level 3 fair value measurement.

F-24

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(c) The estimated fair value of the historical shipper status was estimated using a form of the income approach, the Greenfield Method. Significant inputs used in this model include estimated cash flows with and without the historical shipper status, and a discount rate. An increase in the cash flows attributable to the shipper would result in an increase in the value of such relationship, while an increase in the discount rate would result in a decrease in the value. We consider this to be a Level 3 fair value measurement.

(d) The estimated fair value of the railcar leases was estimated using a form of the income approach, the Lost Income Method. Significant inputs used in this model include the cost of providing services with and without the favorable railcar leases and a discount rate. An increase in market rates of railcar leases would result in an increase in the value attributable to the acquired leases. We consider this to be a Level 3 fair value measurement.

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

(f) A deferred tax liability has been recorded since the acquired intangible assets will not be deductible for tax purposes until the eventual sale of the company.

Purchase Price Allocation of HIE – The preliminary 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 using valuation techniques described in notes (a) through (g) described below.

	Fair Value at		Fair Value
	September 25, 2013		Technique
	(in thousands)
Net working capital	$	462,059	(a)
Property, plant and equipment		58,782	(b)
Land		39,800	(c)
Trade names and trade marks		4,689	(d)
Goodwill		13,613	(e)
Contingent consideration liability		(11,980)	(f)
Other noncurrent liabilities		(6,384)	(g)
	$	560,579

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

(b) The estimated 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 estimated 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 estimated 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.

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

(f) The estimated 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 noncurrent assets and liabilities are recorded at their estimated net present value as estimated by management.

Assets and Liabilities Measure at Fair Value on a Recurring Basis

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

F-25

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

	December 31,
	2013			2012
Stock price	$	22.30		$	12.00
Initial exercise price	$	0.1		$	0.1
Term (years)		8.67			9.67
Risk-free rate		2.78	%		1.68	%
Expected volatility		52.9	%		75.0	%

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 Warrants was $21.64 and $11.30 per share, or approximately $17.3 million and $10.9 million, as of December 31, 2013 and 2012, respectively. Since the 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 Warrants other than changes in the value of our common stock. Increases in the value of our common stock will directly be correlated to increases in the value of the Warrants. Likewise, a decrease in the value of our common stock will result in a decrease in the value of the Warrants.

Debt Prepayment Derivative - Our Loan Agreement contained mandatory repayments subject to premiums as set forth in the agreement. Factors such as the sale of assets, distributions from our investment in Piceance Energy, issuance of additional debt or issuance of additional equity may result in a mandatory prepayment. We considered the contingent prepayment feature to be an embedded derivative which was bifurcated from the loan and accounted for as a derivative. The fair value of the embedded derivative was estimated using an income valuation technique and a Crystal Ball forecast. The fair value measurement is considered to be a Level 3 fair value measurement. We do not believe that changes to the inputs in the model would have a significant impact on the valuation of the embedded derivative, other than a change to the estimate of the probability that a triggering event would occur. An increase in the probability of a triggering event occurring would cause an increase in the fair value of the embedded derivative. Likewise, a decrease in the probability of a triggering event occurring would cause a decrease in the value of the embedded derivative. At December 31, 2012, we estimated the fair value of the embedded derivative to be $145 thousand based on the probability of us repaying the loan prior to maturity. In November 2013, we repaid in full and terminated all of our obligations, including any repayment premiums, under this Loan Agreement (other than the new Tranche B loans described above) extinguishing the liability (see Note 10 - Debt).

Derivative instruments – With the acquisition of Texadian, we assumed certain open positions consisting of non-exchange traded fixed price physical contracts. These contracts were not treated as normal purchase or normal sales contracts and changes in fair value were recorded in earnings. In addition, we had certain exchange traded oil contracts that settled during the period and had no open positions as of December 31, 2013.  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. As of December 31, 2013, we had no open positions relating to these non-exchange traded fixed price physical contracts for which we have not elected the normal purchase or normal sale exception.

Contingent consideration liability – As described in Note 4, the purchase price for our acquisition of HIE may be increased pursuant to an earn out provision. The initial value of the contingent consideration was estimated to be approximately $12.0million. The liability is re-measured at the end of each reporting period using the valuation technique as described above. We do not believe that there has been a material change in the liability from September 25, 2013 through December 31, 2013.

Financial Statement Impact

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012 and their placement with our consolidated balance sheet consist of the following (in thousands):

	Location on
	Consolidated		Fair Value at	Fair Value at
	Balance Sheet	December 31, 2013		December 31, 2012
Commodities – physical forward     contracts	Prepaid and other current assets	$	—	$	(307)
Commodities – exchange traded     futures	Prepaid and other current assets		—		542
Warrant derivatives	Derivative liabilities		(17,336)		(10,900)
Contingent consideration liability	Contingent consideration liability		(11,980)		—
Debt repayment derivative	Derivative liabilities		—		(45)

F-26

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

The following table summarizes the pre-tax effect resulting from changes in fair value of derivative instruments charged directly to earnings (in thousands):

				September 1
				through
		December 31, 2013		December 31, 2012
		Gain (loss)		Gain (loss)
	Income Statement	recognized in		recognized in
	Classification	income		income
Derivatives not designated as     hedges:
Warrants	Change in value of warrants	$	(10,114)	$	(4,280)
Debt repayment derivative	Interest expense and financing costs, net		45		—
Commodities - exchange traded     futures	Gain on derivative instruments, net		104		—
Commodities - physical forward     contracts	Gain on derivative instruments, net		306		—

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012 and their level within the fair value hierarchy is as follows (in thousands):

	December 31, 2013
	Fair Value		Level 1		Level 2		Level 3
Liabilities
Warrants derivative	$	(17,336)	$	—	$	—	$	(17,336)
Contingent consideration liability		(11,980)		—		—		(11,980)
	$	(29,316)	$	—	$	—	$	(29,316)

	December 31, 2012
	Fair Value		Level 1		Level 2		Level 3
Assets
Commodities – exchange traded futures	$	542	$	542	$	—	$	—
Liabilities
Warrants derivative	$	(10,900)	$	—	$	—	$	(10,900)
Debt prepayment derivative		(45)		—		—		(45)
Commodities – physical forward contracts		(307)		—		(307)		—
	$	(11,252)	$	—	$	(307)	$	(10,945)

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

Description	2013		2012
Balance, at beginning of period	$	(10,945)	$	(6,665)
Settlements		3,723		—
Acquired		(11,980)		—
Total unrealized losses included in earnings		(10,114)		(4,280)
Transfers		—		—
Balance, at end of period	$	(29,316)	$	(10,945)

The carrying value and fair value of long-term debt and other financial instruments as of December 31, 2013 and 2012 is as follows (in thousands):

F-27

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

 

	December 31, 2013
	Carrying Value		Fair Value(1)
Tranche B	$	19,480	$	18,800
ABL Facility		51,800		51,800
HIE Retail Credit Agreement		26,000		26,000
Warrants		17,336		17,336
Contingent consideration liability		11,980		11,980

	December 31, 2012
	Carrying Value		Fair Value(1)
Long-term debt	$	7,391	$	10,900
Warrants		10,900		10,900
Debt repayment derivative		45		45

_________________________________________________________ 

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

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.

We estimate our long term debt’s fair value using a discounted cash flow analysis and an estimate of the current yield of5.72%and5.72%as of December 31, 2013 and 2012, respectively, by reference to market interest rates for term debt of comparable companies.

F-28

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Note 12 – Defined Contribution Plans

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 year ended December 31, 2013, we made contributions to the plans totaling approximately $502 thousand. There were no such plans in place for the period from September 1, 2012 through December 31, 2012.

Note 13 - Commitments and Contingencies

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.  

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.

Regulation of Greenhouse Gases. The United States Environmental Protection Agency (“US EPA”) has begun regulating greenhouse gases under the Clean Air Act Amendments of 1990 (the “Clean Air Act”).  New construction or material expansions that meet certain greenhouse gas emissions thresholds will likely require that, among other things, a greenhouse gas 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 greenhouse gas emissions.

Furthermore, the US EPA is currently developing refinery-specific greenhouse gas regulations and performance standards that are expected to impose, on new and modified operations, greenhouse gas 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.

In 2007, the State of Hawaii passed Act 234, which required that greenhouse gas emissions be rolled back on a state wide 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 greenhouse gas emissions were reported to the US 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 greenhouse gas 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 greenhouse gas 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 (the “RFS2”). In August 2012, the US 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 US  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 US 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 US 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 nation-wide 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.

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

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PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Consent Decree. Tesoro is currently negotiating a consent decree with the US 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 (the “Consent Decree”), including the Hawaii refinery.  It is anticipated that the Consent Decree will be finalized sometime during 2014 and will require certain capital improvements to our refinery to reduce emissions of air pollutants.

It is not possible at this time to estimate the cost of compliance with the ultimate decree. 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 has agreed, at its expense, to replace the existing underground storage tanks at certain retail assets.

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 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 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.

Helicopter Litigation.

HIE is the defendant in a lawsuit styled State of Hawaii Department of Transportation Airports Division et al. v. Tesoro Hawaii, Civil No. 09-2253-09 JHC. In this matter, the insurance company for the State of Hawaii is seeking reimbursement of the attorney’s fees and costs incurred by outside council to defend against Tesoro Hawaii’s third-party complaints for contribution in three previously-settled underlying litigation matters. The underlying litigation was filed by three helicopter tour operators flying on the Island of Kauau. The helicopter tour operators allege bad jet fuel caused the formation of coking deposits in their engines which resulted in millions of dollars of repair costs and lost income. There were no in-flight issues.

Tesoro Hawaii filed third-party complaints against the State of Hawaii in each of the three underlying lawsuits alleging that any fuel issues arose from improper design and maintenance of the underground pipeline and dispensers owned and maintained by the State of Hawaii. The helicopter operators settled with the State of Hawaii, and Tesoro Hawaii and its aviation liability insurers subsequently settled with the helicopter operators.

The lawsuit alleges that the State of Hawaii was entitled to a defense and indemnity under the terms of its lease for the Tesoro Hawaii facility at the Lihue airport. The suit alleges defense costs of approximately $2 million in the underlying lawsuits. The State of Hawaii and its insurance company have since demanded $3.25 million. The issue at trial is ultimately whether Tesoro Hawaii owed a contractual duty to pay for the State of Hawaii’s defense against Tesoro Hawaii’s third-party complaints against the State of Hawaii for the State’s own negligence. The case is set for a bench trial in September 2014.

There is a companion lawsuit by the State of Hawaii and its insurance company against Tesoro Hawaii’s former liability insurer on the same issues. The Court previously held by way of a Motion for Summary Judgment that Tesoro Hawaii’s insurer had a duty to defend the State of Hawaii against Tesoro Hawaii’s third-party complaints. That matter is going to trial in July 2014 on the issue of damages only (e.g. the reasonable amount of attorney’s fees and costs the State of Hawaii is entitled to for the defense of the third-Party Complaints in the underlying lawsuits).

We do not believe that any loss relating to this litigation is probable. However, should any loss become probable before the end of the measurement period, such loss would be reflected as a purchase price adjustment relating to the HIE Acquisition.

Recovery Trusts

On the date we emerged from bankruptcy, or the Emergence Date, two trusts were formed; the Wapiti Recovery Trust (the “Wapiti Trust”) and the Delta Petroleum General Recovery Trust (the “General Trust,” and together with the Wapiti Trust, the “Recovery Trusts”). The Recovery Trusts were 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 Recovery Trusts were funded with $1.0 million each pursuant to the Plan.

In September 2012, the Wapiti Trust settled all causes of action against Wapiti Oil & Gas, LLC (“Wapiti Oil & Gas”). Wapiti Oil & Gas made a one-time cash payment in the amount of $1.5 million to the Wapiti Trust, as consideration for the release of claims against it. These proceeds were then distributed to us, along with funds remaining from the initial funding of the Wapiti Trust of approximately $1.0 million. The Wapiti Trust was liquidated during 2013.

The General Trust is pursuing all bankruptcy causes of action not otherwise vested in the Wapiti Trust, 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(the “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.

From the Emergence Date through December 31, 2013, the Recovery Trusts have 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. The entire $5.2 million was released prior to December 31, 2012.

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, 2012, the Recovery Trustee settled 25 claims with an aggregate face amount of $6.6 million for approximately $259 thousand in cash and 20,275 shares of common stock.  Pursuant to the Plan, during the year ended December 31, 2013, the Recovery Trustee settled an additional 59 claims with an aggregate face amount of $26.9 million for approximately $5.4 million in cash and 208,460 shares of common stock.

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PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

 

As of December 31, 2013, it is estimated that a total of 28 claims totaling approximately $40.2 million remain to be resolved by the Recovery Trustee. The largest remaining proof of claim was filed by the US 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 the Predecessor company 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, 2013 and 2012, we have reserved approximately $3.8 million and $8.7 million, respectively, representing the estimated value of claims remaining to be settled which are deemed probable and estimable at period end. A summary of claims is as follows (in thousands, except number of filed claims):

	Emergence-Date August 31, 2012				From Emergence-Date through December 31, 2012
											Remaining Filed
	Filed Claims				Settled Claims						Claims
								Consideration
	Count		Amount		Count	Amount		Cash		Stock	Count	Amount
U.S. Government Claims		3	$	22,364	—	$	—	$	—	—	3	$	22,364
Former Employee Claims		32		16,380	13		3,685		230	20	19		12,695
Macquarie Capital (USA) Inc.		1		8,672	—		—		—	—	1		8,672
Swann and BuzzardCreek    RoyaltyTrust		1		3,200	—		—		—	—	1		3,200
Other Various Claims*		75		23,114	12		2,915		29	—	63		20,199
Total		112	$	73,730	25	$	6,600	$	259	20	87	$	67,130

	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.

Capital Leases

Within our refining, distribution and marketing 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):

2014	$	382
2015		382
2016		382
2017		382
2018		420
Thereafter		420
Total minimum lease payments		2,368
Less amount representing interest		634
Total minimum rental payments	$	1,734

F-31

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Operating Leases

Within our refining, distribution and marketing 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):

2014	$	22,724
2015		13,277
2016		12,362
2017		10,375
2018		9,244
Thereafter		25,614
Total minimum rental payments	$	93,596

Rent expense for the year ended December 31, 2013 and for the period from September 1, 2012 through December 31, 2012 was approximately $6.2 million and $61 thousand, respectively.

Major Customers

For the year ended December 31, 2013, no individual customer accounted for more than 10% of our consolidated revenue. For the period September 1, 2012 to December 31, 2012, we had one customer that accounted for 96% of our total oil and natural gas sales. During the period from January 1, 2012 to August 31, 2012, our Predecessor had two customers that accounted individually for 59% and 24%, respectively, of its total oil and natural gas sales. 

Other

On April 22, 2013, Texadian entered into a terminaling and storage agreement whereby the operator will provide Texadian with storage facilities, access to a marine terminal and pipelines, and railcar offloading services. The initial term of the agreement is for a period of four years and Texadian’s minimum commitment during the initial term is approximately $28 million.

Note 14 - Stockholders’ Equity

Pursuant to the Plan, on the Emergence Date, (i) all shares of our common stock outstanding prior to the Effective Date were cancelled, (ii) each holder of our 7% senior unsecured notes due 2015 and our 3 ³/₄% senior convertible notes due 2037 received, in exchange for its total claim (including principal and interest), its pro rata portion of 14,573,608 shares of our common stock, (iii) each holder of an allowed general unsecured claim received, in exchange for its total claim, its pro rata portion of 191,973 shares of our common stock, and (iii) the Lenders under the Loan Agreement received warrants to purchase up to an aggregate of 959,213 shares of our common stock (which number of shares may be increased to an aggregate of 1,220,000 shares of our common stock pursuant to the terms of the Warrant Issuance Agreement).  

F-32

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

Amendments to the Certificate of Incorporation and Bylaws

Pursuant to the Plan, on the Emergence Date, our certificate of incorporation and bylaws were amended and restated in their entirety.

Under the restated certificate of incorporation, the total number of all shares of capital stock that we are authorized to issue is 303 million shares, consisting of 300 million shares of common stock and 3 million shares of preferred stock, par value $0.01 per share. The restated 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 Code, of us or any direct or indirect subsidiary thereof.

On November 25, 2013, our amended and restated certificate of incorporation was further amended to (i) increase the authorized shares of Common Stock from 300,000,000 to 500,000,000 and (ii) revise certain provisions regarding approval by the company’s Board of Directors of transfers of Common Stock by holders of five percent or more of the outstanding Common Stock.

Preferred Stock

As of December 31, 2013 and 2012, no shares of preferred stock were outstanding.

Common Stock

On December 31, 2012, a total of 3,052 shares of our common stock were issued to members of our Board of Directors in lieu of a cash fee for their service on the Board. We recognized compensation costs of approximately $33 thousand relating to these shares, which represent their estimated fair value on the date of grant based on the previous 20 days average trading price of our common stock which ranged from $10.00 to $12.00 per share of common stock. Due to our limited daily trading activity, we believe that this represents a more accurate reflection of the fair value of our common stock.

On September 13, 2013, we entered into a Common Stock Purchase Agreement pursuant to which we agreed to sell shares of our common stock at a price of $13.90per share, as adjusted to reflect the one for ten reverse stock split effective for trading purposes on January 29, 2014 (the “Reverse Stock Split”),  in a private placement transaction (the “Private Placement”) in reliance upon an exemption from registration pursuant to Regulation D under the Securities Act of 1933. Certain purchasers, namely, ZCOF Par Petroleum Holdings, L.L.C., an affiliate of Zell Credit Opportunities Master Fund, L.P. (“ZCOF”), and affiliates of Whitebox Advisors, LLC (“Whitebox”), each owned 10% or more of the our common stock directly or through affiliates prior to the execution of the Common Stock Purchase Agreement and are deemed to be our affiliates as a result of such ownership. ZCOF and Whitebox have representatives on our board of directors.

On September 25, 2013, we completed the Private Placement and issued approximately 14.4 million shares of common stock resulting in aggregate gross proceeds to us of approximately $200 million. We did not engage any investment advisors with respect to the Private Placement, and no finders’ fees or commissions were paid to any party in connection therewith. The proceeds from the Private Placement were used to fund a portion of the purchase price of the HIE acquisition.

During the year ended December 31, 2013, we issued approximately 208,512 shares of our common stock for settlement of bankruptcy claims, approximately 183,390 shares due to the exercise of Warrants and approximately5,585shares of unrestricted common stock to certain key employees and directors. We recognized compensation costs of approximately $90thousand relating to these shares, which represent their estimated fair value on the date of grant based on the previous 20 days average trading price of our common stock which ranged from $12.22 to $19.87per share of common stock.

Registration Rights Agreements

Pursuant to the Plan, on the Effective Date, we entered into a registration rights agreement (the “Registration Rights Agreement”) providing the stockholders party thereto (the “Stockholders”) with certain registration rights.

The Registration Rights Agreement states that, among other things, at any time after the earlier of the consummation of a qualified public offering or 60 days after the Effective Date, 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 on Form S-1 or S-3, or any other appropriate form under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, 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, on any form for which we then qualify and which is available for the sale of the Registrable Shares in accordance with the intended methods of distribution thereof, with respect to the Demand Registration. We are required to use commercially reasonable efforts to cause the registration statement to be declared effective as soon as practicable after such filing. We will not be obligated (i) to effect a Demand Registration within 90 days after the effective date of a previous Demand Registration, other than for a shelf registration, or (ii) to effect a Demand Registration unless the Demand Request is for a number of Registrable Shares with an expected market value that is equal to at least (x) $15 million as of the date of such Demand Request or is for one hundred percent of the demanding Stockholder’s Registrable Shares with respect to any Demand Registration made on Form S-1 or (y) $5 million as of the date of such Demand Request with respect to any Demand Registration made on Form S-3.

F-33

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

Upon receipt of any Demand Request, we are required to give written notice, within ten (10) days of such Demand Registration, to all other holders of Registrable Shares, who will have the right to elect to include in such Demand Registration such portion of their Registrable Shares as they may request, subject to certain exceptions.

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.

The rights of a holder of Registrable Shares may be transferred, assigned or otherwise conveyed on to any transferee or assignee of such Registrable Shares, subject to applicable state and federal securities laws and regulations, our Certificate of Incorporation and the Stockholders Agreement. We will be responsible for expenses relating to the registrations contemplated by the Registration Rights Agreement.

The registration rights granted in the Registration 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.

In connection with the closing of the sale of the 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 U.S. Securities and Exchange Commission 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.

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. We will accrue an obligation for this registration rights agreement when it is probable that an obligation has been incurred and the amount can be reasonably determined.

Incentive Plan

On December 20, 2012, our Board of Directors (the “Board”) approved the Par Petroleum Corporation 2012 Long Term Incentive Plan (the “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. In addition, in December 2012, we approved a new compensation plan for our directors. Our directors receive an annual retainer of $50 thousand, paid quarterly in cash or shares of our common stock at the election of the director. In addition, the Chairman of the Audit Committee receives an additional annual retainer of $15 thousand and the members of the Audit Committee (other than the Chairman) receive an annual retainer of $5 thousand, such retainers paid quarterly in cash or shares of our common stock at the election of the director. There are no fees for the members of any other committee or for attendance at meetings. Our directors are also entitled to receive an annual grant of restricted stock on the last day of each calendar year with a target value of $75 thousand, with the number of shares determined by the 60-day volume weighted average share price as of the day prior to the grant date.

On December 31, 2012, a total of 219,183 shares of restricted common stock were granted to members of the Board of Directors and certain employees. During the year ended December 31, 2013, an additional 355,481 shares of restricted stock were granted to certain employees. Restricted stock granted to members of the Board vests in full after one year from the date of grant, while most restricted stock granted to employees vests on a pro-rata basis over five years. For the year ended December 31, 2013, the following activity occurred under our Incentive Plan (in thousands, except per share amounts):

F-34

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

	Shares	Weighted- Average Grant Date Fair Value
Non vested balance, beginning of period	219	$	12.00
Granted	356		18.32
Vested	(51)		12.00
Forfeited	—		—
Non vested balance, end of period	524	$	16.29
Available for grant	1,025

For the year ended December 31, 2013, we recognized compensation costs of approximately $1.2 million related to restricted stock awards. As of December 31, 2013, there is approximately $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 4.37 years. The grant date fair value was estimated using the previous 20 days average trading price of our common stock.

Predecessor Stock Compensation Plans

On December 22, 2009, the Predecessor’s stockholders approved its 2009 Performance and Equity Plan (the “2009 Plan”). On June 21, 2011, the Predecessor granted 489,227 shares of non-vested common stock to certain employees. The shares vested in full on the earlier of a change in control or July 1, 2012. In conjunction with this grant, the Predecessor agreed to establish a “floor” price for the value of the shares on the date of vesting equal to the value of the shares on the grant date ($5.50 per share). In the event that the market price of the shares on the date of vesting was lower than the floor price on the date of vesting, the difference would be paid to the employees in cash. The compensation expense for the shares consists of a fixed equity component ($5.50 per share) and a variable liability component (based on the difference between the market price of the shares, if lower, and the floor price of the shares), both of which are included as a component of general and administrative expense in the accompanying Predecessor consolidated statement of operations. The Predecessor recognized stock compensation expense of approximately $1.9 million for the period from January 1, 2012 through August 31, 2012, which is included in general and administrative expenses. Under the terms of the Plan, the Predecessor’s stock compensation plans, and all awards issued under such plans, were canceled.

A summary of the stock option activity under the Predecessor’s various plans and related information for the period from January 1 through August 31, 2012 follows:

	Period from January 1 through August 31, 2012
	Options	Weighted-Average Exercise Price		Weighted-Average Remaining  Contractual Term	Aggregate Intrinsic Value
Outstanding-beginning of year	150,300	$	75.00
Granted	—		—
Exercised	—		—
Expired / canceled	(150,300)		(75.00)
Outstanding-end of year	—	$	—	—	$	—
Exercisable-end of year	—	$	—	—	$	—

A summary of the restricted stock (nonvested stock) activity under the Predecessor’s plan and related information for the period from January 1 through August 31, 2012 follows (in thousands, except share and per share amounts):

	Period from January 1 through August 31, 2012
	Nonvested Stock	Weighted-Average Grant-Date Fair Value		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
Nonvested-beginning of year	558,301	$	7.45
Granted	—		—
Vested	—		—
Expired / canceled	(558,301)		(7.45)
Nonvested-end of year	—	$	—	—	$	—

F-35

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

 

Note 15 - Income Taxes

Under the Plan of Reorganization, our prepetition debt securities, primarily prepetition notes, were extinguished. Absent an exception, a debtor recognizes cancellation of debt income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. Tax regulations provide that a debtor in a bankruptcy case may exclude CODI from income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of our equity upon emergence from Chapter 11 bankruptcy proceedings, we were able to retain a significant portion of our NOLs and other “Tax Attributes” after reduction of the Tax Attributes for CODI realized on emergence from Chapter 11 and certain prior interest payments on debt converted to equity. Our NOLs have been reduced by approximately $225 million of CODI as a result of emergence from Chapter 11.

Pursuant to the Plan, on the Emergence Date, the existing equity interests of the Predecessor were extinguished. New equity interests were issued to creditors in connection with the terms of the Plan, resulting in an ownership change as defined under Section 382 of the Code. Section 382 generally places a limit on the amount of net operating losses and other tax attributes arising before the change that may be used to offset taxable income after the ownership change. We believe, however, 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 net operating losses; however the net operating losses are eliminated should another ownership change occur within two years. Our amended and restated certificate of incorporation places restrictions upon the ability of the equity interest holders to transfer their ownership in us. These restrictions are designed to provide us with the maximum assurance that another ownership change does not occur that could adversely impact our net operating loss carry forwards.

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, 2013 and 2012.

During the years ended December 31, 2013 and 2012, 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 2014 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:

	Successor				Predecessor
			Period from		Period from
			September 1		January 1
	Year Ended		through		through
	December 31,		December 31,		August 31,
	2013			2012		2012
Current:
U.S.—Federal	$	—	$	—	$	—
U.S.—State		(179)		—		—
Deferred:
U.S.—Federal		(14)		(2,757)		—
U.S.—State		193		—		—
Total	$	—	$	(2,757)	$	—

F-36

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

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: 

	Successor						Predecessor
				Period from			Period from
				September 1			January 1
	Year Ended			through			through
	December 31,			December 31,			August 31,
	2013			2012			2012
Federal statutory rate		(35.0)	%		(35.0)	%		(35.0)	%
State income taxes, net of federal benefit		0.1	%		—			—
Change in valuation allowance		21.7	%		(2.0)	%		(33.0)
Professional fees related to bankruptcy reorganization		—			8.0	%		17.0	%
Revenue from Wapiti Trust settlement		—			5.0	%		—
Cancellation of debt tax attribute reduction		—			—			51.0	%
Permanent Items		4.1	%
Provision to return adjustments		9.1	%		—			—
Actual income tax rate		—	%		(24.0)	%		—	%

Deferred tax assets (liabilities) are comprised of the following at December 31, 2013 and 2012 (in thousands):

	2013			2012
Deferred tax assets:
Net operating loss	$	540,867	$	450,195
Capital loss carry forwards		26,141		26,141
Property and equipment		34,683		23,045
Investment in Piceance Energy		32,138		45,172
Derivative instruments		—		1,498
Accrued bonuses		—		—
Trust liabilitiy		1,327		—
Other		1,183		1,506
Total deferred tax assets		636,339		547,557
Valuation allowance		(633,954)		(544,442)
Net deferred tax assets	$	2,385	$	3,115
Deferred tax liabilities:
Property and equipment	$	5	$	—
Texadian Energy intangibles		2,380		3,083
Prepaid insurance, marketable securities and other		—		32
State liabilities		216		—
Total deferred tax liabilities	$	2,601	$	3,115
Total deferred tax liability, net	$	(216)	$	—

We have net operating loss carryovers as of December 31, 2013 of $1.3 billion for federal income tax purposes. If not utilized, the tax net operating loss carryforwards will expire during 2027 through 2032. Our capital loss carryovers as of December 31, 2013 are $74.7 million. If not utilized, these carryovers will expire during 2015 and 2016. We also have Alternative Minimum Tax Credit Carryovers of $0.8 million. These credits do not expire; however, we must first generate regular taxable income before they can be used. We will not likely generate regular taxable income utilized our net operating loss carry over.

F-37

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

 

Note 16 - Loss Per Share

The following table sets forth the computation of basic and diluted loss per share (in thousands, except per share amounts):

	Successor				Predecessor
			September 1		January 1
	Year Ended		through		through
	December 31,		December 31,		August 31,
	2013		2012		2012
Net loss attributable to common stockholders	$	(70,621)	$	(8,839)	$	(45,437)
Basic weighted-average common shares     outstanding		19,740		15,734		28,841
Add: dilutive effects of stock options and     unvested stock grants (1)		—		—		—
Diluted weighted-average common stock outstanding		19,740		15,734		28,841
Basic loss per common share attributable to     common stockholders:
Net loss (1)	$	(3.57)	$	(0.56)	$	(1.57)
Diluted loss per common share attributable to     common stockholders:
Net loss (1)	$	(3.57)	$	(0.56)	$	(1.57)

________________________________________________________

^{(1) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Therefore, we have utilized the basic weighted-average common shares outstanding to calculate both basic and diluted loss per share for all parties presented.}

Weighted average potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following (in thousands):

	Successor		Predecessor
		Period from	Period from
		September 1	January 1
	Year Ended	through	through
	December 31,	December 31,	August 31,
	2013	2012	2012
Stock issuable upon conversion of convertible notes	—	—	379
Stock options	—	—	150
Non-vested restricted stock	523	—	558
Total potentially dilutive securities	523	—	1,087

Note 17 - Segment Information

Following our acquisitions of HIE and Texadian, we have three business segments: (i) Refining, Distribution and Marketing, (ii) Natural Gas and Oil Operations and (iii) Commodity Marketing andLogistics. Corporate and Other includes trust litigation and settlements and other administrative costs.Summarized financial information concerning reportable segments consists of the following (in thousands):

For the year ended December 31, 2013	Refining, Distribution and Marketing		Natural Gas and Oil Operations		Commodity Marketing and Logistics		Corporate and Other		Total
Sales and operating revenues	$	778,126	$	7,739	$	100,149	$	—	$	886,014
Depreciation, depletion, amortization     and accretion		2,267		1,686		2,009		20		5,982
Operating income (loss)		(19,318)		246		9,126		(29,367)		(39,313)
Loss from unconsolidated affiliate										(2,941)
Interest expense and financing costs, net										(19,471)
Other income (expense)										808
Change in value of common stock warrants										(10,114)
Gain on derivative instruments										410
Loss before income taxes										(70,621)
Income tax benefit										—
Net loss									$	(70,621)
Capital expenditures, including acquisitions	$	567,332	$	471	$	(1,300)	$	544	$	567,047

F-38

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements 

Following our acquisition of Texadian, at December 31, 2012, we had two business segments: (i) Natural Gas and Oil Operations and (ii) Commodity Marketing and Logistics. For the period from September 1 through December 31, 2012, all of the operations as reported on our consolidated statement of operations related to Natural Gas and Oil Operations. For the period from September 1 through December 31, 2012, expenditures for long term assets, including goodwill and other intangible assets by segment were as follows (in thousands):

	Natural Gas and Oil Operations		Commodity Marketing and Logistics		Corporate and Other		Total
Capital expenditures, including acquisitions	$	415	$	17,439	$	—	$	17,854

Total assets by segment were as follows (in thousands):

	Refining, Distribution  and Marketing		Natural Gas  and Oil  Operations		Commodity  Marketing and Logistics		Corporate and Other		Total
At December 31, 2013	$	655,712	$	109,316	$	52,048	$	10,009	$	827,085
At December 31, 2012	$	—	$	116,034	$	62,754	$	10,794	$	189,582

Note 18 - Related Party Transactions

Certain of our stockholders who are lenders under the Loan Agreement received Warrants exercisable for shares of common stock in connection with such loan (see Note 10 - Debt).

Certain of our stockholders and their affiliates who are owners of 10% or more of our common shares participated in the Stock Sale (see Note 14 - Stockholders’ Equity).

On September 17, 2013, we entered into letter agreements (the “Services Agreements”) with Equity Group Investments, an affiliate of ZCOF (“EGI”), and Whitebox.  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 indemnity each of them for certain losses incurred by them relating to or arising out of the Services Agreements or the services provided thereunder.

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 this agreement during 2013. 

F-39

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

 

Note 19 - Reorganization Under Chapter 11, Fresh-Start Reporting and the Effects of the Plan 

In December 2011 and January 2012, Delta and its subsidiaries filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). Delta and its subsidiaries included in the bankruptcy petitions are collectively referred to as the “Debtors.”

In March 2012, the Bankruptcy Court approved the procedures relating to plans of reorganization as well as asset sales. Following completion of the asset sales, the Debtors obtained approval from the Bankruptcy Court to proceed with Laramie Energy II, LLC (“Laramie”) as the sponsor of a plan of reorganization (the “Plan”). In June 2012, Delta entered into a Contribution Agreement (the “Contribution Agreement”) with a new joint venture formed by Delta and Laramie, Piceance Energy LLC (“Piceance Energy”), and Laramie to effect the transactions contemplated by Plan.

The Plan was declared effective on August 31, 2012 (the “Emergence Date”). On the Emergence Date, Delta consummated the transaction contemplated by the Contribution Agreement and each of Delta and Laramie contributed to Piceance Energy their respective assets in the Piceance Basin. Piceance Energy is owned 66.66% by Laramie and 33.34% by Delta. At the closing, Piceance Energy entered into a new credit agreement, borrowed $100 million under that agreement, and distributed approximately $72.6 million net of settlements to the company and approximately $24.9 million to Laramie. The company used its distribution to pay bankruptcy expenses and to repay its secured debt. The company also entered into a new credit facility and borrowed $13 million under that facility at closing, and used those funds primarily to pay bankruptcy claims and expenses.

Following the reorganization, Par retained its interest in the Point Arguello Unit offshore California and other miscellaneous assets and certain tax attributes, including significant net operating loss carryforwards. Based upon the Plan as confirmed by the Bankruptcy Court, Delta’s creditors were issued approximately 14.8 million shares of common stock, and Delta’s former stockholders received no consideration under the Plan.

Contemporaneously with the consummation of the Contribution Agreement, the company, through a wholly-owned subsidiary, entered into a Limited Liability company Agreement with Laramie that will govern the operations of Piceance Energy.

On the Emergence Date, Par adopted fresh-start reporting resulting in us becoming a new entity for financial reporting purposes. Accordingly, our consolidated financial statements for periods prior to August 31, 2012 reflect the operations of Delta prior to reorganization (hereinafter also referred to as the “Predecessor”) and are not comparable to the consolidated financial statements presented on or after August 31, 2012. Fresh-start reporting was required upon emergence from Chapter 11 because (i) holders of voting shares immediately before confirmation of the Plan received less than 50% of the emerging entity and (ii) the reorganization value of our assets immediately before confirmation of the Plan was less than our post-petition liabilities and allowed claims. Fresh-start reporting results in a new basis of accounting and reflects the allocation of our estimated fair value to underlying assets and liabilities. The effects of the implementation of the Plan and fresh-start adjustments are reflected in the results of operations of the Predecessor in the eight month period ended August 31, 2012. Our estimates of fair value are inherently subject to significant uncertainties and contingencies beyond our reasonable control. Accordingly, there can be no assurance that the estimates, assumptions, valuations, appraisals and financial projections will be realized, and actual results could vary materially. Moreover, the market value of our common stock may differ materially from the equity valuation for accounting purposes.

In the application of fresh-start reporting, a successor entity must determine a value to be assigned to the equity of the emerging company as of the date of adoption of fresh-start reporting, which for us is August 31, 2012, the date the Debtors emerged from Chapter 11. To facilitate this calculation, we first determined the enterprise value of the Successor and the individual components of the opening balance sheet. The most significant item is our 33.34% interest in Piceance Energy, the value of which was estimated to be approximately $105.3 million as of the Emergence Date. We also considered the fair value of the other remaining assets. See Note 11 - Fair Value Measurements for a detailed discussion of fair value and the valuation techniques.

The estimated enterprise value and the equity value are highly dependent on the achievement of the future financial results contemplated in the projections that were set forth in the Plan. The estimates and assumptions made in the valuation are inherently subject to significant uncertainties. The primary assumptions for which there is a reasonable possibility of the occurrence of a variation that would have significantly affected the reorganization value include the assumptions regarding our direct ownership of estimated proved reserves, our indirect ownership of estimated proved reserves through our equity ownership in Piceance Energy, operating expenses, the amount and timing of capital expenditures and the discount rate utilized.

F-40

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements 

Fresh-start reporting reflects the value of the Successor as determined in the confirmed Plan. Under fresh-start reporting, our asset values are remeasured and allocated based on their respective fair values in conformity with the acquisition method of accounting for business combinations. The reorganization values approximated the fair values of the identifiable net assets. Liabilities existing as of the Effective Date, other than deferred taxes and derivatives, were recorded at the present value of amounts expected to be paid using appropriate risk adjusted interest rates. Deferred taxes and derivatives were determined in conformity with applicable accounting standards. Predecessor accumulated depreciation, accumulated amortization and retained deficit were eliminated. Under the Plan, our priority non-tax claims and secured claims are unimpaired in accordance with the Bankruptcy Code. Each general unsecured claim and noteholder claims received its pro rata share of new common stock of Par in full satisfaction of its claims.

The following condensed consolidated balance sheet presents the implementation of the Plan and the adoption of fresh-start reporting as of the Effective Date. Reorganization adjustments have been recorded within the condensed consolidated balance sheet to reflect the effects of the Plan, including discharge of liabilities subject to compromise and the adoption of fresh-start reporting.

F-41

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements 

		August 31, 2012
				Plan of			Fresh Start
				Reorganization			Reporting
		Predecessor		Adjustments			Adjustments			Successor
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$	1,954	$	74,167	(a)	$			$	4,882
				(45,035)	(c)
				(24,204)	(d)
				(2,000)	(e)
Trust assets		—		3,446	(e)					3,446
Restricted cash		—		20,359	(d)					20,359
Trade accounts receivable, net		3,708		(1,727)	(a)		(1,981)	(g)		—
Prepaid assets		4,777					(4,777)	(g)		—
Prepaid reorganization costs		1,326					(1,326)	(g)		—
Total current assets		11,765								28,687
Property and equipment
Oil and gas properties
Unproved		84					(84)	(g)		—
Proved		759,755		(740,392)	(a)		(14,776)	(g)		4,587
Land		4,000		(4,000)	(a)					—
Other		73,021		(47,493)	(a)		(21,289)	(g)		4,239
Total property and equipment		836,860								8,826
Less accumulated depreciation and depletion		(642,172)		607,603	(a)		34,569	(g)		—
Property and equipment, net		194,688								8,826
Long-term assets:
Investments in unconsolidated affiliates		3,629		105,344	(a)		(3,629)	(g)		105,344
Other long-term assets		307					(253)	(g)		54
Total long-term assets		3,936								105,398
Total assets	$	210,389							$	142,911
LIABILITIES AND EQUITY
Current liabilities
Liabilities not subject to compromise
Debtor in possession financing	$	56,535		(56,535)	(c)				$	—
Accounts payable and other accrued liabilities		4,897								4,897
Other accrued liabilities		9,224		(2,685)	(b)					2,640
				(1,500)	(c)
				(3,845)	(d)
				1,446	(e)
Accrued reorganization and trustee expense		70,656								7,537
Liabilities subject to compromise
3 3/4% Senior notes		115,000		(115,000)	(b)					—
7% Senior convertible notes		150,000		(150,000)	(b)					—
Accounts payable and other accrued liabilities		17,203		(2,560)	(a)		(1,981)	(g)		12,336
				(3,526)	(d)		3,200	(g)
Total current liabilities		352,859								19,873
Long-term liabilities
Liabilities not subject to compromise
Long – term debt		—		6,335	(c)					6,335
Derivative liabilities		—		6,665	(c)					6,665
Asset retirement obligations		4,414		(3,938)	(a)					476
Total liabilities		357,273								33,349
Stockholders’ equity
Common stock		288		1,457	(b)		(288)	(f)		1,477
				20	(d)
Additional paid-in capital		1,643,285		100,084	(b)		288	(f)		108,085
				1,318	(d)		(1,636,890)	(h)
Retained earnings (accumulated deficit)		(1,790,457)		166,144	(b)		(14,765)	(g)		—
				2,188	(d)		1,636,890	(h)
Total stockholders’ equity (deficit)		(146,884)								109,562
Total liabilities and equity (deficit)	$	210,389							$	142,911

F-42

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements 

 

Notes to Plan of Reorganization and Fresh Start Accounting Adjustments

(a)	Reflects the contribution of certain of our oil and gas assets and related prepaid expenses and asset retirement obligations to Piceance Energy in exchange for cash and a 33.34% interest in Piceance Energy.
(b)	Reflects the extinguishment of secured debt in exchange for common stock of the Successor. On the Emergence Date, we issued 14,573,608 shares of our common stock and warrants to acquire 959,213 shares of our common stock to the holders of our secured debt or their affiliates. We estimated the fair value of our common stock to be $7.00 per share on the Emergence Date. Accordingly, we recorded a gain on the settlement of secured debt within Reorganization items of approximately $166.1 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
(c)	Reflects the Successor drawing $13 million under the Loan Agreement (see Note 10 - Debt) to repay amounts outstanding under the DIP Credit Facility with those proceeds and cash from contribution of assets to Piceance Energy.
(d)	Reflects the settlement of other claims with common stock of Successor and cash. On the Emergence Date, we issued 191,973 shares of our common stock to various creditors. We estimated the fair value of our common stock to be $7.00 per share on the Emergence Date. Accordingly, we recorded a gain on settlement of liabilities within Reorganization items of approximately $2.2 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
(e)	Reflects the funding of the Recovery Trusts (see Note 13 - Commitments and Contingencies).
(f)	Reflects the cancellation of Predecessor common stock.
(g)	Reflects adjustments to remaining assets due to fresh-start reporting. On the Emergence Date, we adjusted the carrying value of our remaining assets to their estimated fair values. As a result of these adjustments, we recorded a loss for changes in asset fair values due to fresh-start reporting adjustments within Reorganization items of approximately $14.8 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
(h)	Reflects the elimination of Predecessor’s accumulated deficit.

Note 20 - Subsequent Events

On the January 23, 2014 and in connection with the consummation of the Reverse Stock Split as described in Note 1-Overview, we and certain of our subsidiaries entered into an Eleventh Amendment to our Loan Agreement pursuant to which the Lender consented to Fractional Share Cash Payments.

As a result of the Reverse Stock Split, every ten pre-split shares of Common Stock issued prior to January 29, 2014, the effective date of the reverse stock split for trading purposes, were exchanged for one post-split share of Common Stock, with fractional shares paid in cash at an amount equal to the product obtained by multiplying (a) the closing price of the Common Stock as reported on the OTCQB Marketplace on January 23, 2014, by (b) the fraction of one share owned by the stockholder. Further, the number of shares of Common Stock issued and outstanding was reduced from approximately 301,141,520 on January 23, 2014 to approximately 30,114,352. The number of authorized shares of Common Stock will remain at 500,000,000 and the par value of the Common Stock will remain at $0.01 per share. 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 outstanding prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis, unless otherwise noted. No adjustments have been made to the share or per share amounts of our Predecessor.

Note 21- Disclosures About Capitalized Costs, Costs Incurred (Unaudited)

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

	Successor				Predecessor
	December 31, 2013		December 31, 2012		August 31, 2012
Company:
Unproved properties	$	—	$	—	$	84
Proved properties		4,949		4,804		759,755
		4,949		4,804		759,839
Accumulated depreciation and depletion		(1,868)		(337)		(642,172)
	$	3,081	$	4,467	$	117,667
Company’s Share of Piceance Energy:
Unproved properties	$	15,763	$	16,180
Proved properties		168,378		134,638
		184,141		150,818
Accumulated depreciation and depletion		(38,452)		(2,808)
	$	145,689	$	148,010

F-43

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statement

(1) The capitalized cost amounts presented are as of August 31, 2012 for the Predecessor and exclude adjustments resulting from the plan or reorganization and fresh-start reporting (see Note 19 - Reorganization Under Chapter 11, Fresh-Start Reporting and the Effects of the Plan).  

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

	Successor				Predecessor
	Year Ended December 31, 2013		Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012
Company:
Development costs incurred on proved undeveloped     reserves	$	—	$	—	$	1,613
Development costs—other		142		—		—
Total	$	142	$	—	$	1,613
Company’s Share of Piceance Energy:
Unproved properties acquisition costs	$	—	$	206
Proved properties acquisition costs (1)		—		32,519
Development costs—other		6,380		291
Total	$	6,380	$	33,016

_______________________________________________________ 

(1) Amount represents our share of proved oil and natural gas property acquired at inception of the formation of Piceance Energy, of which $24.2 million relates to oil and natural gas properties purchased from Delta contemplated as part the emergence from bankruptcy and $8.3 million relates oil and natural gas properties purchased from Laramie.

F-44

PAR PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements

At December 31, 2011, the company had $8,770 of suspended exploratory well cost subject to evaluation. Upon the emergency from Bankruptcy on August 31, 2012 all capitalized oil and natural gas property costs, including suspended exploratory well cost, were transferred to Piceance in exchange for cash and a 33.34% equity interest in Piceance. For the period from September 1, 2012 through December 31, 2012 and for the year ended December 31, 2013 neither the company 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 December 31, 2012 and 2013 that were being evaluated.

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

	Successor				Predecessor
	Year Ended December 31, 2013		September 1 through December 31, 2012		January 1 through August 31, 2012
Company:
Revenue:
Oil and gas revenues	$	7,739	$	2,144	$	23,079
Expenses:
Production costs		5,696		1,688		16,980
Depletion and amortization		1,593		370		16,041
Exploration		—		—		2
Abandoned and impaired properties		—		—		151,347
Results of operations of oil and gas producing activities	$	450	$	86	$	(161,291)
Company’s share of Piceance Energy:
Revenue:
Oil and gas revenues	$	20,364	$	6,464
Expenses:
Production costs		9,885		3,033
Depletion and amortization		8,855		2,808
Results of operations of oil and gas producing activities	$	1,624	$	623
Total Company and Piceance Energy income from     operations of oil and gas producing activities	$	2,074	$	709

F-45

 

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Note 22 - 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 the company’s oil and natural gas reserves and present values as of December 31, 2013 and 2012,  and August 31, 2012 were prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers.  

A summary of changes in estimated quantities of proved reserves for the year ended December 31, 2013 and for respective periods in 2012 is as follows:

	Gas	Oil	NGLS	Total
	(MMcf)	(MBbl)	(MBb1)	(MMcfe) (5)
Company:
Estimated Proved Reserves: Balance at January 1, 2012     (Predecessor) (1)	87,209	494	—	90,173
Revisions of quantity estimate	—	85	—	512
Sale/disposition of properties (2)	(82,357)	(235)	—	(83,770)
Production	(4,852)	(67)	—	(5,256)
Estimated Proved Reserves: Balance at August 31, 2012     (Successor)	—	277	—	1,659
Revisions of quantity estimate	456	31	—	643
Production	(10)	(22)	—	(139)
Estimated Proved Reserves: Balance at December 31, 2012     (Successor)	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     (Successor)	662	236	—	2,078
Company’s Share of Piceance Energy:
Estimated Proved Reserves: Balance at September 1, 2012	—	—	—	—
Transfer from investees (3)	83,915	560	4,228	112,639
Revisions of quantity estimate	8,053	41	387	10,621
Extensions and discoveries	32,073	236	1,778	44,151
Production	(1,391)	(6)	(48)	(1,711)
Estimated Proved Reserves: Balance at December 31, 2012	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	186,597	584	7,401	234,509
Total Estimated Proved Reserves: Balance at December 31, 2013	187,259	820	7,401	236,587
Proved developed reserves
December 31, 2012	158	286	—	1,875
December 31, 2012—Company Share of Piceance Energy	48,680	237	2,253	63,617
Total December 31, 2012	48,838	523	2,253	65,492
Proved undeveloped reserves
December 31, 2012	288	—	—	288
December 31, 2012—Company Share of Piceance Energy	73,970	594	4,092	102,083
Total December 31, 2012	74,258	594	4,092	102,371
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

	CIG per Mbtu		WTI per Bbl
Base pricing, before adjustments for contractual     differentials: (4)
August 31, 2012	$	2.75	$	90.85
December 31, 2012	$	2.56	$	91.21
December 31, 2012 – Piceance	$	2.56	$	91.21
December 31, 2013	$	3.53	$	96.91
December 31, 2013 – Piceance	$	3.53	$	96.91

_________________________________________________________

⁽¹⁾ At January 1, 2012, gas is based on 70,982 MMcf of natural gas and 4,057 MBbl of natural gas liquids, with liquids converted to gas using a ratio of 4 Mcf to 1 barrel.

⁽²⁾ On August 31, 2012, substantially all of the reserves of the company were transferred to Piceance Energy in exchange for a 33.34% equity ownership interest (See Note 3 - Investment in Piceance Energy).

⁽³⁾ On August 31, 2012, certain reserves held by Delta Petroleum and by Laramie were transferred to Piceance Energy in exchange for a 33.34% and a 66.66% equity ownership interest, respectively (See Note 3 - Investment in Piceance Energy).

⁽⁴⁾ 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.

⁽⁵⁾ MMcfe is based on a ratio of 6 Mcf to 1 barrel.

F-46

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

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.

	Successor				Predecessor
	December 31,				August 31,
	2013		2012		2012
	(in thousands)				(in thousands)
Company:
Future net cash flows	$	26,861	$	30,444	$	28,691
Future costs:
Production		21,999		20,596		19,973
Development and abandonment		319		319		319
Income taxes1		—		—		—
Future net cash flows		4,543		9,529		8,399
10% discount factor		(1,006)		(1,519)		(1,176)
Standardized measure of discounted future net cash      flows	$	3,537	$	8,010	$	7,223
Company’s Share of Piceance Energy:
Future net cash flows	$	984,205	$	568,706
Future costs:
Production		430,506		199,277
Development and abandonment		234,905		154,054
Income taxes1		—		—
Future net cash flows		318,794		215,375
10% discount factor		(229,469)		(143,416)
Standardized measure of discounted future net      cash flows	$	89,325	$	71,959
Total Company and Company share of equity      investee in the standardized measure of      discounted future net revenues	$	92,862	$	79,969

________________________________________________

¹            No income tax provision is included in the standardized measure calculation shown above as the company does 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.

The principal sources of changes in the standardized measure of discounted net cash flows for the year ended December 31, 2013 and for the respective periods during 2012 are as follows (in thousands): 

	Successor
	December 31,		Company Share of Piceance Energy December 31,		Total
	2013		2013		2013
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

	Successor						Predecessor
	Period from September 1, through December 31,		Company Share of Piceance Energy September 1, through December 31,		Total		January 1, through August 31,
	2012		2012		2012		2012
Beginning of the year							$	129,695
Beginning of the period	$	7,223	$	—	$	7,223		—
Transfer from investees		—		55,253		55,253		—
Sales of oil and gas production during the period,      net of production costs		(456)		(3,639)		(4,095)		(5,954)
Net change in prices and production costs		(667)		(139)		(806)		378
Changes in estimated future development costs		—		5		5		—
Extensions, discoveries and improved recovery		763		569		1,332		—
Revisions of previous quantity estimates, estimated      timing of development and other		648		13,708		14,356		(7,439)
Sales/disposition of reserves in place		—		—		—		(118,104)
Other		258		4,360		4,618		—
Accretion of discount		241		1,842		2,083		8,647
End of period	$	8,010	$	71,959	$	79,969	$	7,223

F-47

 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange of Act of 1934, we have caused this Form 10-K to be signed on our behalf by the undersigned, thereunto duly authorized, in the City of Houston and State of Texas on the 31^st day of March, 2014.

PAR PETROLEUM CORPORATION
By:	/s/ William Monteleone.
	William Monteleone, Chief Executive Officer
By:	/s/ Christopher Micklas
	Christopher Micklas, Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Form 10-K has been signed below by the following persons on our behalf and in the capacities and on the dates indicated.

Signature and Title	Date
/s/ William Monteleone	March 31, 2014
William Monteleone, Chief Executive Officer (Principal Executive Officer)
/s/ Christopher Micklas	March 31, 2014
Christopher Micklas, Chief Financial Officer (Principal Financial and Accounting Officer)
/s/ Jacob Mercer	March 31, 2014
Jacob Mercer, Director
/s/ Benjamin Lurie	March 31, 2014
Benjamin Lurie, Director
/s/ Michael Keener	March 31, 2014
Michael Keener, Director
/s/ L. Melvin Cooper	March 31, 2014
L. Melvin Cooper, Director

EX-21.1

Exhibit 21.1

Subsidiaries of the Registrant

Name	Jurisdiction
Par Piceance Energy Equity, LLC	Delaware
Texadian Energy, Inc.	Delaware
Hawaii Pacific Energy, LLC	Delaware
EWI, LLC	Delaware
Par Washington, LLC	Delaware
Par Utah, LLC	Delaware
Par New Mexico, LLC	Delaware
HEWW Equipment, LLC	Delaware
HIE Retail, LLC	Hawaii
Hawaii Independent Energy LLC	Hawaii
Smiley’s Super Service, Inc.	Hawaii
Texadian Energy Canada Limited	Alberta, Canada
Piceance Energy, LLC (33.34% interest)	Delaware

EX-23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-192519 on Form S-3 and Registration Statement No. 333-185612 on Form S-8 of our report dated March 31, 2014, relating to the consolidated financial statements of Par Petroleum Corporation as of and for the year ended December 31, 2013, appearing in this Annual Report on Form 10-K of Par Petroleum Corporation for the year ended December 31, 2013.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 31, 2014

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the registration statements on Form S-8 (File No. 333-185612) and on Form S-3 (File No. 333-192519) of Par Petroleum Corporation of our report dated March 27, 2013 and updated for Note 14 on March 31, 2014, with respect to the consolidated balance sheet of Par Petroleum Corporation and subsidiaries as of December 31, 2012 and the related consolidated statements of operations and comprehensive loss, changes in equity, and cash flows for the period from September 1, 2012 through December 31, 2012 and of our report dated February 28, 2014, with respect to the balance sheet of Piceance Energy, LLC as of December 31, 2013 and the related statements of operations, members’ equity, and cash flows for the year then ended, appearing in the Annual Report on Form 10-K of Par Petroleum Corporation for the fiscal year ended December 31, 2013.

EKS&H LLLP

Denver, Colorado

March 31, 2014

EX-23.3

Exhibit 23.3

Consent of Independent Registered Public Accounting Firm

To the Board of Directors

Par Petroleum Corporation, Successor to Delta Petroleum Corporation

We consent to the incorporation by reference in the registration statement on Form S-8 (No. 333-185612) and on Form S-3 (File No. 333-192519)) of Par Petroleum Corporation (formerly Delta Petroleum Corporation) and subsidiaries (the Predecessor) of our report dated March 27, 2013, with respect to the consolidated statements of operations (Predecessor), changes in equity (Predecessor), and cash flows (Predecessor) for the period January 1, 2012 through August 31, 2012, which report appears in the December 31, 2013 annual report on Form 10-K of Par Petroleum Corporation.

Our report over the consolidated financial statements contains an explanatory paragraph that states that the Predecessor filed a petition for reorganization under Chapter 11 of the United States Bankruptcy Code on December 16, 2011. The Predecessor’s plan of reorganization became effective and the Company emerged from bankruptcy protection on August 31, 2012. In connection with its emergence from bankruptcy, the Company adopted the guidance for fresh start accounting in conformity with FASB ASC Topic 852, Reorganizations, effective as of August 31, 2012. Accordingly, the Predecessor’s consolidated financial statements prior to August 31, 2012 are not comparable to its consolidated financial statements for periods after August 31, 2012.

/s/ KPMG LLP

KPMG LLP

Denver, Colorado

March 31, 2014

EX-23.4

Exhibit 23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion in this Annual Report on Form 10-K of Par Petroleum Corporation for the year ended December 31, 2013, of our report dated March 17, 2014, with respect to estimates of reserves and future net revenue of Par Petroleum Corporation, as of December 31, 2013, and to all references to our firm included in this Annual Report. 

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III
	Chairman and Chief Executive Officer

Dallas, Texas

March 31, 2014

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13a-14(a)/15d-14(a) PROMULGATED UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, William Monteleone, certify that:

1. I have reviewed this annual report on Form 10-K of Par Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 31, 2014

/s/ William Monteleone

William Monteleone

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13a-14(a) PROMULGATED UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Christopher Micklas, certify that:

1. I have reviewed this annual report on Form 10-K of Par Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 31, 2014

/s/ Christopher Micklas

Christopher Micklas

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Par Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, William Monteleone, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ William Monteleone

William Monteleone

Chief Executive Officer

March 31, 2014

EX-32.2

Exhibit 32.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Par Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Christopher Micklas, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Christopher Micklas

Christopher Micklas

Chief Financial Officer

March 31, 2014

EX-99.1

 

March 17, 2014

Mr. Chris Micklas

Par Petroleum Corporation

800 Gessner Road, Suite 875

Houston, Texas 77024

Dear Mr. Micklas:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2013, to the Par Petroleum Corporation (Par) interest in certain oil and gas properties located in California, Colorado, and New Mexico. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Par. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Par's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Par interest in these properties, as of December 31, 2013, to be:

	Net Reserves						Future Net Revenue (M$)
	Oil		NGL		Gas				Present Worth
Category	(MBBL)		(MBBL)		(MMCF)		Total		at 10%
Proved Developed Producing		362.3		1,138.8		33,357.3		78,084.3		47,349.2
Proved Developed Non-Producing		39.1		488.6		12,376.9		29,364.7		10,372.1
Proved Undeveloped		418.6		5,773.9		141,524.8		215,888.3		35,140.6
Total Proved		820.1		7,401.3		187,259.0		323,337.3		92,861.9

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Par's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Par's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

 

 

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2013. For oil and NGL volumes, the average West Texas Intermediate spot price of $96.91 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average CIG Rocky Mountains spot price of $3.527 per MMBTU is used for the Colorado properties and the average Henry Hub spot price of $3.670 per MMBTU is used for the New Mexico properties. These average regional spot prices are adjusted by lease for energy content and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $89.70 per barrel of oil, $32.05 per barrel of NGL, and $3.740 per MCF of gas. By area, these average adjusted prices are $101.08 per barrel of oil for the California properties; $85.33 per barrel of oil, $32.05 per barrel of NGL, and $3.740 per MCF of gas for the Colorado properties; and $91.30 per barrel of oil and $4.576 per MCF of gas for the New Mexico properties.

Operating costs used in this report are based on operating expense records of Par. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Since all properties are nonoperated, headquarters general and administrative overhead expenses of Par are not included. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Par and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties, except for the saltwater disposal wells and the California properties. For the saltwater disposal wells, abandonment costs used in this report are the operator's estimates of the costs to abandon the wells, net of any salvage value. For the California properties, abandonment costs used in this report are Par's estimates of the costs to abandon the wells, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Par interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Par receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

 

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones, non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Par, other interest owners, various operators of the properties, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
	/s/ C.H. (Scott) Rees III
By:
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer

	/s/ Dan Paul Smith		/s/ John G. Hattner
By:		By:
	Dan Paul Smith, P.E. 49093		John G. Hattner, P.G. 559
	Senior Vice President		Senior Vice President
Date Signed:  March 17, 2014		Date Signed:  March 17, 2014

BWJ: JSB

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

Definitions - Page 2 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

Definitions - Page 3 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

Definitions - Page 4 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Definitions - Page 5 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
	a.	Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
	b.	Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
	a.	Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
	b.	Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
	c.	Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
	d.	Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
	e.	Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
	f.	Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Definitions - Page 6 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
	Ÿ	The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
	Ÿ	The company's historical record at completing development of comparable long-term projects;
	Ÿ	The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
	Ÿ	The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
	Ÿ	The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 7 of 7

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements, Nonrecurring [Table Text Block]

The estimates of fair value of the net assets were reflected in the Successor’s consolidated balance sheet as of August 31, 2012.

	Fair Value at		Fair Value
	August 31, 2012		Technique
	(in thousands)
Oil and gas properties
Proved	$	4,587	(a)(b)
Other assets
Frac tanks		1,400	(c)
Compressors		2,800	(c)
Miscellaneous		39	(d)
Investment in Piceance Energy		105,344	(e)

(a) Certain proved property was valued using the cost valuation technique. A significant input in this measurement was the estimated cost of the properties. A change in that estimated cost would be directly correlated to change in the estimated fair value of the property. We consider this to be a Level 3 fair value measurement.

(b) The estimated fair value of our Point Arguello Unit offshore California was valued using a market valuation technique based on standalone bids received by third-parties during the sale process. We consider this to be a Level 2 fair value measurement.

(c) The estimated fair value of our frac tanks and compressor units was valued using a market valuation technique which was based on published listings of similar equipment or standalone bids received by third-parties. We consider these to be Level 2 fair value measurements.

(d) Miscellaneous assets (assets that we were unable to value using the income or market valuation techniques) were valued using the cost valuation technique. We consider this to be a Level 3 fair value measurement.

(e) The estimated fair value of our investment in Piceance Energy was based on its enterprise value and uses various valuation techniques including (i) an income approach based on proved developed reserves’ future net income discounted back to net present value based on the weighted average cost of capital for comparable independent oil and natural gas producers, and (ii) a market multiple approach. Proved property was valued using the income approach. A discounted cash flow model was prepared based off of an independent reserve report with a discount rate of 10% applied to proved developed producing reserves, 15% to proved developed non-producing reserves and 20% to proved undeveloped reserves. The prices for oil and natural gas were forecasted based on NYMEX strip pricing adjusted for basis differentials. For the market multiple approach, we reviewed the transaction values of recent similar asset transactions and compared the purchase price per Mcfe of proved developed reserves and purchase price per Mcfe per day of net equivalent production of those transactions to the independent reserve report. Unproved acreage was valued using a cost approach based on recent sales of acreage in the area. Based on these valuations, the equity value of our 33.34% interest in Piceance Energy was estimated to be approximately $105.3 million on the Emergence date. We consider this to be a Level 3 fair value measurement.

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

Significant inputs used in the Monte Carlo Simulation Analysis include:

	December 31,
	2013			2012
Stock price	$	22.30		$	12.00
Initial exercise price	$	0.1		$	0.1
Term (years)		8.67			9.67
Risk-free rate		2.78	%		1.68	%
Expected volatility		52.9	%		75.0	%

Fair Value, Assets Measured on Recurring Basis [Table Text Block]

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012 and their placement with our consolidated balance sheet consist of the following (in thousands):

	Location on
	Consolidated		Fair Value at	Fair Value at
	Balance Sheet	December 31, 2013		December 31, 2012
Commodities – physical forward     contracts	Prepaid and other current assets	$	—	$	(307)
Commodities – exchange traded     futures	Prepaid and other current assets		—		542
Warrant derivatives	Derivative liabilities		(17,336)		(10,900)
Contingent consideration liability	Contingent consideration liability		(11,980)		—
Debt repayment derivative	Derivative liabilities		—		(45)

Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location [Table Text Block]

The following table summarizes the pre-tax effect resulting from changes in fair value of derivative instruments charged directly to earnings (in thousands):

				September 1
				through
		December 31, 2013		December 31, 2012
		Gain (loss)		Gain (loss)
	Income Statement	recognized in		recognized in
	Classification	income		income
Derivatives not designated as     hedges:
Warrants	Change in value of warrants	$	(10,114)	$	(4,280)
Debt repayment derivative	Interest expense and financing costs, net		45		—
Commodities - exchange traded     futures	Gain on derivative instruments, net		104		—
Commodities - physical forward     contracts	Gain on derivative instruments, net		306		—

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012 and their level within the fair value hierarchy is as follows (in thousands):

	December 31, 2013
	Fair Value		Level 1		Level 2		Level 3
Liabilities
Warrants derivative	$	(17,336)	$	—	$	—	$	(17,336)
Contingent consideration liability		(11,980)		—		—		(11,980)
	$	(29,316)	$	—	$	—	$	(29,316)

	December 31, 2012
	Fair Value		Level 1		Level 2		Level 3
Assets
Commodities – exchange traded futures	$	542	$	542	$	—	$	—
Liabilities
Warrants derivative	$	(10,900)	$	—	$	—	$	(10,900)
Debt prepayment derivative		(45)		—		—		(45)
Commodities – physical forward contracts		(307)		—		(307)		—
	$	(11,252)	$	—	$	(307)	$	(10,945)

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

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

Description	2013		2012
Balance, at beginning of period	$	(10,945)	$	(6,665)
Settlements		3,723		—
Acquired		(11,980)		—
Total unrealized losses included in earnings		(10,114)		(4,280)
Transfers		—		—
Balance, at end of period	$	(29,316)	$	(10,945)

Fair Value and Carrying Value Liabilities Measured On Recurring Basis [Table Text Block]

The carrying value and fair value of long-term debt and other financial instruments as of December 31, 2013 and 2012 is as follows (in thousands):

	December 31, 2013
	Carrying Value		Fair Value(1)
Tranche B	$	19,480	$	18,800
ABL Facility		51,800		51,800
HIE Retail Credit Agreement		26,000		26,000
Warrants		17,336		17,336
Contingent consideration liability		11,980		11,980

	December 31, 2012
	Carrying Value		Fair Value(1)
Long-term debt	$	7,391	$	10,900
Warrants		10,900		10,900
Debt repayment derivative		45		45

_________________________________________________________ 

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

HIE Retail, LLC [Member]

Fair Value Disclosures [Abstract]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Table Text Block]

Purchase Price Allocation of HIE – The preliminary 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 using valuation techniques described in notes (a) through (g) described below.

	Fair Value at		Fair Value
	September 25, 2013		Technique
	(in thousands)
Net working capital	$	462,059	(a)
Property, plant and equipment		58,782	(b)
Land		39,800	(c)
Trade names and trade marks		4,689	(d)
Goodwill		13,613	(e)
Contingent consideration liability		(11,980)	(f)
Other noncurrent liabilities		(6,384)	(g)
	$	560,579

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

(b) The estimated 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 estimated 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 estimated 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.

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

(f) The estimated 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 noncurrent assets and liabilities are recorded at their estimated net present value as estimated by management.

Texadian Energy Inc [Member]

Fair Value Disclosures [Abstract]

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Table Text Block]

Purchase Price Allocation of Texadian – The fair values of the assets acquired and liabilities assumed as a result of the Texadian acquisition were estimated as of the date of the acquisition using valuation techniques described in notes (a) through (f) described below.

	Fair Value at		Fair Value
	December 31, 2012		Technique
	(in thousands)
Net non-cash working capital	$	3,631	(a)
Supplier relationship		3,360	(b)
Historical shipper status		2,200	(c)
Railcar leases		3,249	(d)
Goodwill		7,756	(e)
Deferred tax liabilities		(2,757)	(f)
	$	17,439

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

(b) The estimated fair value of the supplier relationship was estimated using a form of the income approach, the Multiple-Period Excess Earnings Method. Significant inputs used in this model include estimated cash flows from the suppliers, customer growth and rates and a discount rate. An increase in the cash flows attributable to the supplier relationships would result in an increase in the value of such relationship, while an increase in the discount rate would result in a decrease in the value. We consider this to be a Level 3 fair value measurement.

(c) The estimated fair value of the historical shipper status was estimated using a form of the income approach, the Greenfield Method. Significant inputs used in this model include estimated cash flows with and without the historical shipper status, and a discount rate. An increase in the cash flows attributable to the shipper would result in an increase in the value of such relationship, while an increase in the discount rate would result in a decrease in the value. We consider this to be a Level 3 fair value measurement.

(d) The estimated fair value of the railcar leases was estimated using a form of the income approach, the Lost Income Method. Significant inputs used in this model include the cost of providing services with and without the favorable railcar leases and a discount rate. An increase in market rates of railcar leases would result in an increase in the value attributable to the acquired leases. We consider this to be a Level 3 fair value measurement.

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

(f) A deferred tax liability has been recorded since the acquired intangible assets will not be deductible for tax purposes until the eventual sale of the company.

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Acquisitions and Dispositions (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Goodwill	$ 20,603	$ 7,756
Contingent consideration liability	(11,980)
Texadian Energy Inc [Member]
Intangible assets	8,809
Goodwill	6,990
Net non cash-working capital	3,097
Deferred tax liabilities	(2,757)
Total	16,139
Hawaii Independent Energy LLC [Member]
Inventory	418,750
Trade accounts receivable	59,485
Prepaids and other current assets	1,978
Property, plant and equipment	58,782
Land	39,800
Intangible assets	4,689
Goodwill	13,613
Accounts payable and other current liabilities	(18,154)
Contingent consideration liability	(11,980)
Other noncurrent liabilities	(6,384)
Total	$ 560,579

XML

Overview (Details Textual) (USD $)		1 Months Ended	12 Months Ended
	Dec. 31, 2013	Jan. 23, 2014 Subsequent Event [Member]	Dec. 31, 2013 Hawaii Independent Energy LLC [Member]	Dec. 31, 2012 Texadian Energy Inc [Member]	Dec. 31, 2012 Delta Petroleum [Member]	Dec. 31, 2012 Piceance Energy [Member]	Dec. 31, 2013 Tesoro Acquisition [Member] Hawaii Independent Energy LLC [Member]
Unsecured Debt					$ 265,000,000
Payments to Acquire Businesses, Gross			75,000,000	14,000,000
Business Combination, Contingent Consideration, Liability	11,980,000		11,980,000				40,000,000
Noncontrolling Interest, Ownership Percentage by Parent						33.34%
Business Combination, Consideration Transferred, Liabilities Incurred				3,000,000
Business Combination, start-up expenses			$ 24,300,000
Stockholders Equity Reverse Stock Split		1:10 reverse stock split

XML

Debt (Details 4)	12 Months Ended
	Dec. 31, 2013
Leverage Ratio Less Than 4.00 [Member]
Debt Instrument [Line Items]
Debt Instrument, Unused Fee Percentage	0.25%
Leverage Ratio Less Than 4.00 [Member] | LIBOR loans [Member]
Debt Instrument [Line Items]
Debt Instrument Revolver Applicable Margin	1.75%
Leverage Ratio Less Than 4.00 [Member] | Base Rate Loans [Member]
Debt Instrument [Line Items]
Debt Instrument Revolver Applicable Margin	(0.25%)
Leverage Ratio 4.00-5.00 [Member]
Debt Instrument [Line Items]
Debt Instrument, Unused Fee Percentage	0.375%
Leverage Ratio 4.00-5.00 [Member] | LIBOR loans [Member]
Debt Instrument [Line Items]
Debt Instrument Revolver Applicable Margin	2.00%
Leverage Ratio 4.00-5.00 [Member] | Base Rate Loans [Member]
Debt Instrument [Line Items]
Debt Instrument Revolver Applicable Margin	0.00%
Leverage Ratio Grater Than 5.00 [Member]
Debt Instrument [Line Items]
Debt Instrument, Unused Fee Percentage	0.50%
Leverage Ratio Grater Than 5.00 [Member] | LIBOR loans [Member]
Debt Instrument [Line Items]
Debt Instrument Revolver Applicable Margin	2.25%
Leverage Ratio Grater Than 5.00 [Member] | Base Rate Loans [Member]
Debt Instrument [Line Items]
Debt Instrument Revolver Applicable Margin	0.25%

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Acquisitions and Dispositions (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Revenues	$ 2,986.8	$ 3,811.1
Net loss	$ (113.6)	$ (12.0)

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Fair Value Measurements (Details 6) (Fair Value, Measurements, Recurring [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Liabilities
Derivative Fair Value Of Derivative Liability	$ (29,316)	$ (11,252)
Contingent consideration liability [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	(11,980)
Commodity Contract [Member] | Exchange Traded Futures [Member]
Assets
Commodities - exchange traded futures		542
Commodity Contract [Member] | Physical Forward Contracts [Member]
Liabilities
Derivative Fair Value Of Derivative Liability		(307)
Warrants derivative [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	(17,336)	(10,900)
Debt Prepayment Derivative [Member]
Liabilities
Derivative Fair Value Of Derivative Liability		(45)
Fair Value Inputs Level 1 [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	0	0
Fair Value Inputs Level 1 [Member] | Contingent consideration liability [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	0
Fair Value Inputs Level 1 [Member] | Commodity Contract [Member] | Exchange Traded Futures [Member]
Assets
Commodities - exchange traded futures		542
Fair Value Inputs Level 1 [Member] | Commodity Contract [Member] | Physical Forward Contracts [Member]
Liabilities
Derivative Fair Value Of Derivative Liability		0
Fair Value Inputs Level 1 [Member] | Warrants derivative [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	0	0
Fair Value Inputs Level 1 [Member] | Debt Prepayment Derivative [Member]
Liabilities
Derivative Fair Value Of Derivative Liability		0
Fair Value Inputs Level 2 [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	0	(307)
Fair Value Inputs Level 2 [Member] | Contingent consideration liability [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	0
Fair Value Inputs Level 2 [Member] | Commodity Contract [Member] | Exchange Traded Futures [Member]
Assets
Commodities - exchange traded futures		0
Fair Value Inputs Level 2 [Member] | Commodity Contract [Member] | Physical Forward Contracts [Member]
Liabilities
Derivative Fair Value Of Derivative Liability		(307)
Fair Value Inputs Level 2 [Member] | Warrants derivative [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	0	0
Fair Value Inputs Level 2 [Member] | Debt Prepayment Derivative [Member]
Liabilities
Derivative Fair Value Of Derivative Liability		0
Fair Value Inputs Level 3 [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	(29,316)	(10,945)
Fair Value Inputs Level 3 [Member] | Contingent consideration liability [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	(11,980)
Fair Value Inputs Level 3 [Member] | Commodity Contract [Member] | Exchange Traded Futures [Member]
Assets
Commodities - exchange traded futures		0
Fair Value Inputs Level 3 [Member] | Commodity Contract [Member] | Physical Forward Contracts [Member]
Liabilities
Derivative Fair Value Of Derivative Liability		0
Fair Value Inputs Level 3 [Member] | Warrants derivative [Member]
Liabilities
Derivative Fair Value Of Derivative Liability	(17,336)	(10,900)
Fair Value Inputs Level 3 [Member] | Debt Prepayment Derivative [Member]
Liabilities
Derivative Fair Value Of Derivative Liability		$ (45)

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Disclosures About Capitalized Costs, Costs Incurred (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Company [Member]	Dec. 31, 2012 Company [Member]	Dec. 31, 2013 Company's Share of Piceance Energy [Member]	Dec. 31, 2012 Company's Share of Piceance Energy [Member]	Aug. 31, 2012 Predecessor [Member] Company [Member]
Oil and Gas In Process Activities [Line Items]
Unproved properties			$ 0	$ 0	$ 15,763	$ 16,180	$ 84
Proved properties	4,949	4,804	4,949	4,804	168,378	134,638	759,755
Oil and Gas Property, Successful Effort Method, Gross, Total			4,949	4,804	184,141	150,818	759,839
Accumulated depreciation and depletion			(1,868)	(337)	(38,452)	(2,808)	(642,172)
Oil and gas property, successful efforts method			$ 3,081	$ 4,467	$ 145,689	$ 148,010	$ 117,667

XML

Disclosures About Capitalized Costs, Costs Incurred (Tables)

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil And Gas Property Successful Effort Method [Table Text Block]

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

	Successor				Predecessor
	December 31, 2013		December 31, 2012		August 31, 2012
Company:
Unproved properties	$	—	$	—	$	84
Proved properties		4,949		4,804		759,755
		4,949		4,804		759,839
Accumulated depreciation and depletion		(1,868)		(337)		(642,172)
	$	3,081	$	4,467	$	117,667
Company’s Share of Piceance Energy:
Unproved properties	$	15,763	$	16,180
Proved properties		168,378		134,638
		184,141		150,818
Accumulated depreciation and depletion		(38,452)		(2,808)
	$	145,689	$	148,010

(1) The capitalized cost amounts presented are as of August 31, 2012 for the Predecessor and exclude adjustments resulting from the plan or reorganization and fresh-start reporting (see Note 19 - Reorganization Under Chapter 11, Fresh-Start Reporting and the Effects of the Plan).  

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

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

	Successor				Predecessor
	Year Ended December 31, 2013		Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012
Company:
Development costs incurred on proved undeveloped     reserves	$	—	$	—	$	1,613
Development costs—other		142		—		—
Total	$	142	$	—	$	1,613
Company’s Share of Piceance Energy:
Unproved properties acquisition costs	$	—	$	206
Proved properties acquisition costs (1)		—		32,519
Development costs—other		6,380		291
Total	$	6,380	$	33,016

_______________________________________________________ 

(1) Amount represents our share of proved oil and natural gas property acquired at inception of the formation of Piceance Energy, of which $24.2 million relates to oil and natural gas properties purchased from Delta contemplated as part the emergence from bankruptcy and $8.3 million relates oil and natural gas properties purchased from Laramie.

Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]

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

	Successor				Predecessor
	Year Ended December 31, 2013		September 1 through December 31, 2012		January 1 through August 31, 2012
Company:
Revenue:
Oil and gas revenues	$	7,739	$	2,144	$	23,079
Expenses:
Production costs		5,696		1,688		16,980
Depletion and amortization		1,593		370		16,041
Exploration		—		—		2
Abandoned and impaired properties		—		—		151,347
Results of operations of oil and gas producing activities	$	450	$	86	$	(161,291)
Company’s share of Piceance Energy:
Revenue:
Oil and gas revenues	$	20,364	$	6,464
Expenses:
Production costs		9,885		3,033
Depletion and amortization		8,855		2,808
Results of operations of oil and gas producing activities	$	1,624	$	623
Total Company and Piceance Energy income from     operations of oil and gas producing activities	$	2,074	$	709

XML

Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Business Acquisition, Pro Forma Information [Table Text Block]

The unaudited pro forma financial information presented below assumes that the Texadian and HIE acquisitions occurred as of January 1, 2012 and combines the Predecessor and Successor periods to include a full year of results for the year ended December 31, 2012. We did not include any adjustments related to the application of fresh-start reporting for the year ended December 31, 2012. 

	2013		2012
(in millions)
Revenues	$	2,986.8	$	3,811.1
Net loss	$	(113.6)	$	(12.0)

Texadian Energy Inc [Member]

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

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

Intangible assets	$	8,809
Goodwill		6,990
Net non cash-working capital		3,097
Deferred tax liabilities		(2,757)
Total, net of cash acquired	$	16,139

Hawaii Independent Energy LLC [Member]

Business Combinations [Abstract]

Schedule Of Purchase Price Allocation Preliminary Estimated Fair Value Of The Assets Acquired And Liabilities Assumed [Table Text Block]

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

Inventory	$	418,750
Trade accounts receivable		59,485
Prepaids and other current assets		1,978
Property, plant and equipment		58,782
Land		39,800
Goodwill		13,613
Intangible assets		4,689
Accounts payable and other current liabilities		(18,154)
Contingent consideration liability		(11,980)
Other noncurrent liabilities		(6,384)
Total	$	560,579

XML

Fair Value Measurements (Details 7) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance, at beginning of period	$ (10,945)	$ (6,665)
Settlements	3,723	0
Acquired	(11,980)	0
Total unrealized losses included in earnings	(10,114)	(4,280)
Transfers	0	0
Balance, at end of period	$ (29,316)	$ (10,945)

XML

Fair Value Measurements (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net, Total	$ 17,439
Net non-cash working capital [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets, Total	3,631	[1]
Supplier relationships [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets, Total	3,360	[2]
Historical shipper status [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets, Total	2,200	[3]
Railcar leases [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets, Total	3,249	[4]
Goodwill [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets, Total	7,756	[5]
Deferred tax liability [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities, Total	$ (2,757)	[6]

[1] Current assets acquired and liabilities assumed were recorded at their net realizable value.

[2] The estimated fair value of the supplier relationship was estimated using a form of the income approach, the Multiple-Period Excess Earnings Method. Significant inputs used in this model include estimated cash flows from the suppliers, customer growth and rates and a discount rate. An increase in the cash flows attributable to the supplier relationships would result in an increase in the value of such relationship, while an increase in the discount rate would result in a decrease in the value. We consider this to be a level 3 fair value measurement.

[3] The estimated fair value of the historical shipper status was estimated using a form of the income approach, the Greenfield Method. Significant inputs used in this model include estimated cash flows with and without the historical shipper status, and a discount rate. An increase in the cash flows attributable to the shipper would result in an increase in the value of such relationship, while an increase in the discount rate would result in a decrease in the value. We consider this to be a level 3 fair value measurement.

[4] The estimated fair value of the railcar leases was estimated using a form of the income approach, the Lost Income Method. Significant inputs used in this model include the cost of providing services with and without the favorable railcar leases and a discount rate. An increase in market rates of railcar leases would result in an increase in the value attributable to the acquired leases. We consider this to be a level 3 fair value measurement.

[5] The excess of the purchase price paid over the fair value of the identifiable assets acquired and liabilities assumed is allocated to goodwill.

[6] A deferred tax liability has been recorded since the acquired intangible assets will not be deductible for tax purposes until the eventual sale of the company.

XML

Stockholders' Equity (Details 2) (Predecessor [Member], USD $)	8 Months Ended
	Aug. 31, 2012
Predecessor [Member]
Nonvested Stock
Non vested balance, beginning of period	558,301
Granted	0
Vested	0
Expired / canceled	(558,301)
Non vested balance, end of period	0
Weighted-Average Grant-Date Fair Value
Non vested balance, beginning of period	$ 7.45
Granted	$ 0
Vested	$ 0
Expired / canceled	$ (7.45)
Non vested balance, end of period	$ 0
Weighted-Average Remaining Contractual Term
Nonvested-end of year	0 years
Aggregate Intrinsic Value
Nonvested-end of year	$ 0

XML

Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Land	$ 39,800	$ 0
Buildings and equipment	65,878	0
Other	1,945	1,415
Property, plant and equipment	107,623	1,415
Proved oil and gas properties	4,949	4,804
Less: accumulated depreciation, depletion and amortization	(3,968)	(373)
Property Plant And Equipment Net	$ 108,604	$ 5,846

XML

Information Regarding Proved Oil and Gas Reserves (Details 1) (USD $) In Thousands, unless otherwise specified	4 Months Ended		12 Months Ended		4 Months Ended		12 Months Ended		8 Months Ended
	Dec. 31, 2012 Company [Member]		Dec. 31, 2013 Company [Member]		Dec. 31, 2012 Company's Share of Piceance Energy [Member]		Dec. 31, 2013 Company's Share of Piceance Energy [Member]		Aug. 31, 2012 Predecessor [Member] Company [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future net cash flows	$ 30,444		$ 26,861		$ 568,706		$ 984,205		$ 28,691
Future costs: Production	20,596		21,999		199,277		430,506		19,973
Future costs: Development and abandonment	319		319		154,054		234,905		319
Income taxes	0	[1]	0	[1]	0	[1]	0	[1]	0	[1]
Future net cash flows	9,529		4,543		215,375		318,794		8,399
10% discount factor	(1,519)		(1,006)		(143,416)		(229,469)		(1,176)
Standardized measure of discounted future net cash flows	8,010		3,537		71,959		89,325		7,223
Total Company and Company share of equity investee in the standardized measure of discounted future net revenues					$ 79,969		$ 92,862

[1] No income tax provision is included in the standardized measure calculation shown above as the Company does 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.

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Fair Value Measurements (Details 4) (Fair Value, Measurements, Recurring [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Contingent consideration liability [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities Fair Value Disclosure	$ (11,980)	$ 0
Prepaid and Other Current Assets [Member] | Commodity Contract [Member] | Physical Forward Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value disclosure	0	(307)
Prepaid and Other Current Assets [Member] | Commodity Contract [Member] | Exchange Traded Futures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value disclosure	0	542
Derivative liabilities [Member] | Warrant [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities Fair Value Disclosure	(17,336)	(10,900)
Derivative liabilities [Member] | Embedded Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities Fair Value Disclosure	$ 0	$ (45)

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Commitments and Contingencies (Details Textual) (USD $) Share data in Millions, unless otherwise specified	12 Months Ended	16 Months Ended		12 Months Ended		12 Months Ended	4 Months Ended	12 Months Ended	8 Months Ended		4 Months Ended	1 Months Ended	4 Months Ended	16 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Texadian [Member]	Dec. 31, 2013 Tesoros [Member]	Dec. 31, 2013 Tesoro Acquisition [Member] Hawaii Independent Energy LLC [Member]	Dec. 31, 2012 Customer One [Member]	Dec. 31, 2013 Predecessor [Member]	Aug. 31, 2012 Predecessor [Member] Customer One [Member]	Aug. 31, 2012 Predecessor [Member] Customer Two [Member]	Dec. 31, 2012 Wapiti Oil And Gas [Member]	Sep. 30, 2012 Wapiti Trust [Member]	Dec. 31, 2012 Wapiti Trust [Member]	Dec. 31, 2013 Wapiti Trust [Member]
Commitments And Contingencies [Line Items]
Recovery Trust Funded Amount	$ 1,000,000	$ 1,000,000
One Time Cash Payment As Consideration For Release Of Claims											1,500,000
Distribution From Trust													5,200,000	5,200,000
Shares Of Beneficial Interest Owned Per 1000 Of Claim								54.4				1.0
Loss Contingency, Estimate of Possible Loss	3,800,000	3,800,000	8,700,000
Long-term Purchase Commitment, Amount				28,000,000
Lessee Leasing Arrangements, Operating Leases, Term of Contract	32 years
Lessee Leasing Arrangements, Capital Leases, Term of Contract	17 years
Lessee Leasing Arrangements, Capital Leases, Renewal Term Description	with four 5-year renewal options
Concentration Risk, Percentage							96.00%		59.00%	24.00%
Percentage Of Beneficial Interest Owned	2.41934%
Contingency Reserve For Litigation	10,000,000	10,000,000
Loss Contingency, Claims Settled, Number	1,000
Renewable Fuel Usage Description	The RFS2 requires an increasing amount of renewable fuel usage, up to 36.0 billion gallons by 2022
Customer Revenue Description	no individual customer accounted for more than 10% of our consolidated revenue
Operating Leases, Rent Expense, Net, Total	6,200,000	61,000
Derivative Assets (Liabilities), at Fair Value, Net, Total					15,000,000
Legal Fees	2,000,000
Loss Contingency, Damages Sought, Value	$ 3,250,000
Indemnification Obligation Limitation, Description						Tesoros indemnification obligations are subject to certain limitations as set forth in the Environmental Agreement. These limitations include a cap of $15 million forcertain of Tesoros indemnification obligationsrelated to certainpre-existing conditions as well as certain restrictions regarding the time limits for submitting notice and supporting documentation for remediation actions.

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Fair Value Measurements (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Hawaii Independent Energy LLC [Member]	Dec. 31, 2013 Piceance Energy [Member]	Aug. 31, 2012 Piceance Energy [Member]	Aug. 31, 2012 Fair Value, Measurements, Nonrecurring [Member] Piceance Energy [Member]		Aug. 31, 2012 Fair Value, Measurements, Nonrecurring [Member] Proved Developed and Producing Reserves	Aug. 31, 2012 Fair Value, Measurements, Nonrecurring [Member] Proved Developed Non Producing Reserves	Aug. 31, 2012 Fair Value, Measurements, Nonrecurring [Member] Proved Undeveloped Reserves
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Cash flow model discount rate								10.00%	15.00%	20.00%
Equity method investment ownership percentage				33.34%	33.34%	33.34%
Investment in Piceance Energy					$ 105,300,000	$ 105,344,000	[1]
Warrants Not Settleable In Cash Fair Value Disclosure, Per Share	$ 21.64	$ 11.30
Warrants Not Settleable in Cash, Fair Value Disclosure	17,300,000	10,900,000
Fair Value Assumptions Historical Volatilities Period1	10 years
Embedded Derivative, Fair Value of Embedded Derivative Liability		145,000
Business Combination, Contingent Consideration, Liability	$ 11,980,000		$ 11,980,000
Fair Value Assumptions, Expected Current Yield	5.72%	5.72%

[1] The estimated fair value of our investment in Piceance Energy was based on its enterprise value and uses various valuation techniques including (i) an income approach based on proved developed reserves’ future net income discounted back to net present value based on the weighted average cost of capital for comparable independent oil and natural gas producers, and (ii) a market multiple approach. Proved property was valued using the income approach. A discounted cash flow model was prepared based off of an independent reserve report with a discount rate of 10% applied to proved developed producing reserves, 15% to proved developed non-producing reserves and 20% to proved undeveloped reserves. The prices for oil and natural gas were forecasted based on NYMEX strip pricing adjusted for basis differentials. For the market multiple approach, we reviewed the transaction values of recent similar asset transactions and compared the purchase price per Mcfe of proved developed reserves and purchase price per Mcfe per day of net equivalent production of those transactions to the independent reserve report. Unproved acreage was valued using a cost approach based on recent sales of acreage in the area. Based on these valuations, the equity value of our 33.34% interest in Piceance Energy was estimated to be approximately $105.3 million on the Emergence date. We consider this to be a Level 3 fair value measurement.

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Stockholders' Equity (Details) (Long Term Incentive Plan, USD $)	12 Months Ended
	Dec. 31, 2013
Long Term Incentive Plan
Stock Awards, Shares
Non vested balance, beginning of period	219,000
Granted	356,000
Vested	(51,000)
Forfeited	0
Non vested balance, end of period	524,000
Available for grant	1,025,000
Stock Awards, Weighted-Average Grant Date Fair Value
Non vested balance, beginning of period	$ 12.00
Granted	$ 18.32
Vested	$ 12.00
Forfeited	$ 0
Non vested balance, end of period	$ 16.29

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Fair Value Measurements (Details 5) (USD $) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013
Gain on derivative instruments, net [Member] | Exchange Traded Futures [Member]
Derivatives not designated as hedges, Gain (loss) recognized in income	$ 0	$ 104
Gain on derivative instruments, net [Member] | Physical Forward Contacts [Member]
Derivatives not designated as hedges, Gain (loss) recognized in income	0	306
Change In Value Of Warrants [Member] | Warrant [Member]
Derivatives not designated as hedges, Gain (loss) recognized in income	(4,280)	(10,114)
Interest expense and financing costs, net [Member] | Debt repayment derivative [Member]
Derivatives not designated as hedges, Gain (loss) recognized in income	$ 0	$ 45

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Debt (Details Textual) (USD $)	4 Months Ended	12 Months Ended		8 Months Ended		12 Months Ended		12 Months Ended		4 Months Ended	12 Months Ended		1 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013 ABL Facility [Member]	Aug. 31, 2012 Predecessor [Member]	Dec. 27, 2012 Financial Standby Letter Of Credit [Member]	Dec. 31, 2013 ABL Revolving Credit Facility [Member]	Sep. 25, 2013 ABL Revolving Credit Facility [Member]	Dec. 31, 2013 Texadian Uncommitted Credit Agreement [Member]	Dec. 27, 2012 Letter of Credit Facility [Member]	Dec. 31, 2013 Warrant Issuance Agreement [Member]	Dec. 31, 2013 Warrant Issuance Agreement [Member]	Dec. 31, 2013 Senior Secured Delayed Draw Term Loan [Member]	Oct. 31, 2013 Senior Secured Delayed Draw Term Loan [Member] Tranche B Term Loan [Member]	Dec. 31, 2013 Senior Secured Delayed Draw Term Loan [Member] Tranche B Term Loan [Member]	Dec. 31, 2013 HIE Retail [Member] Term Loan [Member] Retail Credit Agreement [Member]	Dec. 31, 2013 HIE Retail [Member] Revolving Credit Facility [Member] Retail Credit Agreement [Member]
Debt Disclosure [Line Items]
Proceeds From Lines Of Credit	$ 35,000,000	$ 159,800,000		$ 23,000,000								$ 30,000,000		$ 65,000,000	$ 26,000,000
Interest rate under credit facility													9.75%	14.75%
Debt Instrument, Face Amount												17,000,000
Interest rate after an event of default														2.50%
Debt instrument principal prepayment amount														100,000
Line credit maximum borrowing amount						125,000,000		50,000,000	30,000,000						30	5
Letters Of Credit Outstanding Amount					11,700,000			41,600,000
Common stock warrant exercise price										0.10	0.10
Common stock warrant expiration period										Aug. 31, 2022	Aug. 31, 2022
Fair value of warrant on grant date											6,600,000
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases						50,000,000
Line Of Credit Facility Amount Outstanding							15,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted										14,859	959,213
Stock Issued To Settle Bankruptcy Claims											228,735
Debt Instrument, Interest Rate Terms						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 LIBO rate specified below (LIBO Rate) 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 LIBO Rate 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 LIBO Rate for a LIBO Rate loan denominated in dollars with a one-month interest period commencing on such day plus 1.00%.
Debt Instrument, Fee						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 LIBO Rate loans, a facing fee and customary administrative fees.
Debt Instrument, Covenant Description						The ABL Facility requires HIE and its subsidiaries and Hawaii Pacific Energy to comply with various affirmative and negative covenants affecting its business and operations, including compliance by HIE in certain circumstances with a minimum ratio of consolidated earnings before interest, taxes, depreciation and amortization (EBITDA), as adjusted, to total fixed charges of 1.0 to 1.0.
Line of Credit Facility, Collateral								Loans and letters of credit issued under the Uncommitted Credit Agreement are secured by a security interest in and lien on substantially all of Texadians 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.
Advances To Be Received Upon Compliance Of Requirements															4
Fixed Charge Coverage Ratio To Be Maintained															1.15:1.00
Excess Cash Flow Recapture Description															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
Line of Credit Facility, Interest Rate Description															The Term Loan will bear interest, at HIE Retails 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 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	Advances under the Revolver will bear interest, at HIE Retails 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
Line of Credit Facility, Commitment Fee Percentage																2.00%
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Exercised											183,389
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number, Beginning Balance										790,683	790,683
Extinguishment of Debt, Amount												$ 6,100,000
Debt, Weighted Average Interest Rate			3.13%

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Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

Note 18 - Related Party Transactions

Certain of our stockholders who are lenders under the Loan Agreement received Warrants exercisable for shares of common stock in connection with such loan (see Note 10 - Debt).

Certain of our stockholders and their affiliates who are owners of 10% or more of our common shares participated in the Stock Sale (see Note 14 - Stockholders’ Equity).

On September 17, 2013, we entered into letter agreements (the “Services Agreements”) with Equity Group Investments, an affiliate of ZCOF (“EGI”), and Whitebox.  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 indemnity each of them for certain losses incurred by them relating to or arising out of the Services Agreements or the services provided thereunder.

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 this agreement during 2013. 

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Summary of Significant Accounting Policies (Details Textual) (USD $)	4 Months Ended	12 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Aug. 31, 2012 Predecessor [Member]	Dec. 31, 2012 Predecessor [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Allowance for Doubtful Accounts Receivable	$ 0	$ 0
Income Tax Expense Benefit	$ (2,757,000)	$ 0	$ 0	$ 154,000,000

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Income tax expense (benefit) consisted of the following:

	Successor				Predecessor
			Period from		Period from
			September 1		January 1
	Year Ended		through		through
	December 31,		December 31,		August 31,
	2013			2012		2012
Current:
U.S.—Federal	$	—	$	—	$	—
U.S.—State		(179)		—		—
Deferred:
U.S.—Federal		(14)		(2,757)		—
U.S.—State		193		—		—
Total	$	—	$	(2,757)	$	—

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

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: 

	Successor						Predecessor
				Period from			Period from
				September 1			January 1
	Year Ended			through			through
	December 31,			December 31,			August 31,
	2013			2012			2012
Federal statutory rate		(35.0)	%		(35.0)	%		(35.0)	%
State income taxes, net of federal benefit		0.1	%		—			—
Change in valuation allowance		21.7	%		(2.0)	%		(33.0)
Professional fees related to bankruptcy reorganization		—			8.0	%		17.0	%
Revenue from Wapiti Trust settlement		—			5.0	%		—
Cancellation of debt tax attribute reduction		—			—			51.0	%
Permanent Items		4.1	%
Provision to return adjustments		9.1	%		—			—
Actual income tax rate		—	%		(24.0)	%		—	%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

Deferred tax assets (liabilities) are comprised of the following at December 31, 2013 and 2012 (in thousands):

	2013			2012
Deferred tax assets:
Net operating loss	$	540,867	$	450,195
Capital loss carry forwards		26,141		26,141
Property and equipment		34,683		23,045
Investment in Piceance Energy		32,138		45,172
Derivative instruments		—		1,498
Accrued bonuses		—		—
Trust liabilitiy		1,327		—
Other		1,183		1,506
Total deferred tax assets		636,339		547,557
Valuation allowance		(633,954)		(544,442)
Net deferred tax assets	$	2,385	$	3,115
Deferred tax liabilities:
Property and equipment	$	5	$	—
Texadian Energy intangibles		2,380		3,083
Prepaid insurance, marketable securities and other		—		32
State liabilities		216		—
Total deferred tax liabilities	$	2,601	$	3,115
Total deferred tax liability, net	$	(216)	$	—

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Fair Value Measurements (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value Measurements [Line Items]
Stock price	$ 22.30	$ 12.00
Initial exercise price	$ 0.1	$ 0.1
Term (years)	8 years 8 months 1 day	9 years 8 months 1 day
Risk-free rate	2.78%	1.68%
Expected volatility	52.90%	75.00%

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013
Sales and operating revenues	$ 2,144	$ 886,014
Depreciation, depletion, amortization and accretion	401	5,982
Operating income (loss)	(5,021)	(39,313)
Loss from unconsolidated affiliate		(2,941)
Interest expense and financing costs, net	1,056	19,471
Other income (expense)	86	808
Change in value of common stock warrants	(4,280)	(10,114)
Gain on derivative instruments	0	410
Loss before income taxes	(11,596)	(70,621)
Income tax benefit	(2,757)	0
Net loss	(8,839)	(70,621)
Capital expenditures, including acquisitions	17,854	567,047
Refining Distribution and Marketing [Member]
Sales and operating revenues		778,126
Depreciation, depletion, amortization and accretion		2,267
Operating income (loss)		(19,318)
Capital expenditures, including acquisitions		567,332
Natural Gas and Oil Operations [Member]
Sales and operating revenues		7,739
Depreciation, depletion, amortization and accretion		1,686
Operating income (loss)		246
Capital expenditures, including acquisitions	415	471
Commodity Marketing And Logistics [Member]
Sales and operating revenues		100,149
Depreciation, depletion, amortization and accretion		2,009
Operating income (loss)		9,126
Capital expenditures, including acquisitions	17,439	(1,300)
Corporate and Other [Member]
Sales and operating revenues		0
Depreciation, depletion, amortization and accretion		20
Operating income (loss)		(29,367)
Capital expenditures, including acquisitions	$ 0	$ 544

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Intangible assets (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets [Table Text Block]

Our intangible assets consist of the following (in thousands):

	December 31,
	2013		2012
Amortized intangible assets:
Gross carrying amount:
Supplier relationships	$	3,360	$	3,360
Rail car leases		3,249		3,249
Historical shipper status		2,200		2,200
Trade names and trademarks		4,689		—
Subtotal		13,498		8,809
Accumulated amortization
Supplier relationships		(258)		—
Rail car leases		(650)		—
Historical shipper status		(1,100)		—
Trade name and trademarks		(320)		—
Subtotal		(2,328)		—
Net:
Supplier relationships		3,102		3,360
Rail car leases		2,599		3,249
Historical shipper status		1,100		2,200
Trade name and trademarks		4,369		—
Total amortized intangible assets, net	$	11,170	$	8,809

Finite-lived Intangible Assets Amortization Expense [Table Text Block]

Expected future amortization expense for each of the next five years and thereafter is as follows (in thousands):

Year Ended	Amount
2014	$	3,571
2015		2,471
2016		2,151
2017		908
2018		258
Thereafter		1,811
	$	11,170

Schedule of Goodwill [Table Text Block]

During the year ended December 31, 2013 the changes in the carrying amount of goodwill for the year ended December 31, 2013 were as follows (in thousands):

Balance at beginning of period	$	7,756
Additions		13,613
Texadian purchase price adjustments		(766)
Balance at end of period	$	20,603

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Investment in Piceance Energy (Details 1) (USD $) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013
Assets
Current assets	$ 59,926	$ 558,373
Current liabilities	(69,977)	(458,708)
Oil, natural gas and natural gas liquids revenues	2,144	7,739
Loss from operations	(5,021)	(39,313)
Net loss	(8,839)	(70,621)
Piceance Energy [Member]
Assets
Current assets	6,275	5,901
Non-current assets	460,991	454,402
Current liabilities	(11,826)	(13,040)
Non-current liabilities	(94,369)	(96,738)
Oil, natural gas and natural gas liquids revenues	19,391	61,091
Loss from operations	(2,095)	(6,765)
Net loss	$ (3,975)	$ (10,546)

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Debt (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
2014	$ 3,250
2015	2,600
2016	22,080
2017	54,400
2018	2,600
Thereafter	11,700
Total	$ 97,280	$ 42,391

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Information Regarding Proved Oil and Gas Reserves (Details Textual)	Dec. 31, 2013 MMcf		Dec. 31, 2012	Dec. 31, 2013 Piceance Energy [Member]	Aug. 31, 2012 Piceance Energy [Member]	Dec. 31, 2013 Natural Gas [Member] MMcf	Dec. 31, 2013 Natural Gas Liquids [Member] MBbls	Dec. 31, 2011 Weighted Average [Member] Natural Gas [Member] MMcf	Dec. 31, 2011 Weighted Average [Member] Natural Gas Liquids [Member] MBbls	Aug. 31, 2012 Reorganized Delta Petroleum [Member] Piceance Energy [Member]	Aug. 31, 2012 Laramie [Member] Piceance Energy [Member]	Dec. 31, 2013 Company [Member] MMcf		Dec. 31, 2012 Company [Member] MMcf		Aug. 31, 2012 Company [Member] MMcf		Dec. 31, 2013 Company [Member] Natural Gas [Member] MMcf	Dec. 31, 2012 Company [Member] Natural Gas [Member] MMcf	Aug. 31, 2012 Company [Member] Natural Gas [Member] MMcf	Dec. 31, 2013 Company [Member] Natural Gas Liquids [Member] MBbls	Dec. 31, 2012 Company [Member] Natural Gas Liquids [Member] MBbls	Aug. 31, 2012 Company [Member] Natural Gas Liquids [Member] MBbls	Dec. 31, 2013 Company's Share of Piceance Energy [Member] MMcf		Dec. 31, 2012 Company's Share of Piceance Energy [Member] MMcf		Aug. 31, 2012 Company's Share of Piceance Energy [Member] MMcf		Dec. 31, 2013 Company's Share of Piceance Energy [Member] Natural Gas [Member] MMcf	Dec. 31, 2012 Company's Share of Piceance Energy [Member] Natural Gas [Member] MMcf	Aug. 31, 2012 Company's Share of Piceance Energy [Member] Natural Gas [Member] MMcf	Dec. 31, 2013 Company's Share of Piceance Energy [Member] Natural Gas Liquids [Member] MBbls	Dec. 31, 2012 Company's Share of Piceance Energy [Member] Natural Gas Liquids [Member] MBbls	Aug. 31, 2012 Company's Share of Piceance Energy [Member] Natural Gas Liquids [Member] MBbls
Reserve Quantities [Line Items]
Ownership interest held in Piceance Energy, percentage				33.34%	33.34%					33.34%	66.66%
Discount Rate Used To Present Value Future Net Revenues From Proved Reserves			10.00%											10.00%
Proved Developed And Undeveloped Reserves Net	236,587	[1]				187,259	7,401	70,982	4,057			2,078	[1]	2,163	[1]	1,659	[1]	662	446	0	0	0	0	234,509	[1]	165,700	[1]	0	[1]	186,597	122,650	0	7,401	6,345	0

[1] MMcfe is based on a ratio of 6 Mcf to 1 barrel.

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Intangible assets (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
Amortized intangible assets, Gross carrying amount	$ 13,498	$ 8,809
Amortized intangible assets, Accumulated Amortization	(2,328)	0
Amortized intangible assets, Net	11,170	8,809
Supplier Relation Ships [Member]
Finite-Lived Intangible Assets [Line Items]
Amortized intangible assets, Gross carrying amount	3,360	3,360
Amortized intangible assets, Accumulated Amortization	(258)	0
Amortized intangible assets, Net	3,102	3,360
Rail car leases [Member]
Finite-Lived Intangible Assets [Line Items]
Amortized intangible assets, Gross carrying amount	3,249	3,249
Amortized intangible assets, Accumulated Amortization	(650)	0
Amortized intangible assets, Net	2,599	3,249
Historical Shipper Status [Member]
Finite-Lived Intangible Assets [Line Items]
Amortized intangible assets, Gross carrying amount	2,200	2,200
Amortized intangible assets, Accumulated Amortization	(1,100)	0
Amortized intangible assets, Net	1,100	2,200
Trade names and trademarks [Member]
Finite-Lived Intangible Assets [Line Items]
Amortized intangible assets, Gross carrying amount	4,689	0
Amortized intangible assets, Accumulated Amortization	(320)	0
Amortized intangible assets, Net	$ 4,369	$ 0

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Information Regarding Proved Oil and Gas Reserves (Tables)

12 Months Ended

Dec. 31, 2013

Oil and Gas Property [Abstract]

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

A summary of changes in estimated quantities of proved reserves for the year ended December 31, 2013 and for respective periods in 2012 is as follows:

	Gas	Oil	NGLS	Total
	(MMcf)	(MBbl)	(MBb1)	(MMcfe) (5)
Company:
Estimated Proved Reserves: Balance at January 1, 2012     (Predecessor) (1)	87,209	494	—	90,173
Revisions of quantity estimate	—	85	—	512
Sale/disposition of properties (2)	(82,357)	(235)	—	(83,770)
Production	(4,852)	(67)	—	(5,256)
Estimated Proved Reserves: Balance at August 31, 2012     (Successor)	—	277	—	1,659
Revisions of quantity estimate	456	31	—	643
Production	(10)	(22)	—	(139)
Estimated Proved Reserves: Balance at December 31, 2012     (Successor)	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     (Successor)	662	236	—	2,078
Company’s Share of Piceance Energy:
Estimated Proved Reserves: Balance at September 1, 2012	—	—	—	—
Transfer from investees (3)	83,915	560	4,228	112,639
Revisions of quantity estimate	8,053	41	387	10,621
Extensions and discoveries	32,073	236	1,778	44,151
Production	(1,391)	(6)	(48)	(1,711)
Estimated Proved Reserves: Balance at December 31, 2012	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	186,597	584	7,401	234,509
Total Estimated Proved Reserves: Balance at December 31, 2013	187,259	820	7,401	236,587
Proved developed reserves
December 31, 2012	158	286	—	1,875
December 31, 2012—Company Share of Piceance Energy	48,680	237	2,253	63,617
Total December 31, 2012	48,838	523	2,253	65,492
Proved undeveloped reserves
December 31, 2012	288	—	—	288
December 31, 2012—Company Share of Piceance Energy	73,970	594	4,092	102,083
Total December 31, 2012	74,258	594	4,092	102,371
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

	CIG per Mbtu		WTI per Bbl
Base pricing, before adjustments for contractual     differentials: (4)
August 31, 2012	$	2.75	$	90.85
December 31, 2012	$	2.56	$	91.21
December 31, 2012 – Piceance	$	2.56	$	91.21
December 31, 2013	$	3.53	$	96.91
December 31, 2013 – Piceance	$	3.53	$	96.91

_________________________________________________________

⁽¹⁾ At January 1, 2012, gas is based on 70,982 MMcf of natural gas and 4,057 MBbl of natural gas liquids, with liquids converted to gas using a ratio of 4 Mcf to 1 barrel.

⁽²⁾ On August 31, 2012, substantially all of the reserves of the company were transferred to Piceance Energy in exchange for a 33.34% equity ownership interest (See Note 3 - Investment in Piceance Energy).

⁽³⁾ On August 31, 2012, certain reserves held by Delta Petroleum and by Laramie were transferred to Piceance Energy in exchange for a 33.34% and a 66.66% equity ownership interest, respectively (See Note 3 - Investment in Piceance Energy).

⁽⁴⁾ 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.

⁽⁵⁾ MMcfe is based on a ratio of 6 Mcf to 1 barrel.

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

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.

	Successor				Predecessor
	December 31,				August 31,
	2013		2012		2012
	(in thousands)				(in thousands)
Company:
Future net cash flows	$	26,861	$	30,444	$	28,691
Future costs:
Production		21,999		20,596		19,973
Development and abandonment		319		319		319
Income taxes1		—		—		—
Future net cash flows		4,543		9,529		8,399
10% discount factor		(1,006)		(1,519)		(1,176)
Standardized measure of discounted future net cash      flows	$	3,537	$	8,010	$	7,223
Company’s Share of Piceance Energy:
Future net cash flows	$	984,205	$	568,706
Future costs:
Production		430,506		199,277
Development and abandonment		234,905		154,054
Income taxes1		—		—
Future net cash flows		318,794		215,375
10% discount factor		(229,469)		(143,416)
Standardized measure of discounted future net      cash flows	$	89,325	$	71,959
Total Company and Company share of equity      investee in the standardized measure of      discounted future net revenues	$	92,862	$	79,969

_________________________________________________

¹ No income tax provision is included in the standardized measure calculation shown above as the company does 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.

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]

The principal sources of changes in the standardized measure of discounted net cash flows for the year ended December 31, 2013 and for the respective periods during 2012 are as follows (in thousands): 

	Successor
	December 31,		Company Share of Piceance Energy December 31,		Total
	2013		2013		2013
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

	Successor						Predecessor
	Period from September 1, through December 31,		Company Share of Piceance Energy September 1, through December 31,		Total		January 1, through August 31,
	2012		2012		2012		2012
Beginning of the year							$	129,695
Beginning of the period	$	7,223	$	—	$	7,223		—
Transfer from investees		—		55,253		55,253		—
Sales of oil and gas production during the period,      net of production costs		(456)		(3,639)		(4,095)		(5,954)
Net change in prices and production costs		(667)		(139)		(806)		378
Changes in estimated future development costs		—		5		5		—
Extensions, discoveries and improved recovery		763		569		1,332		—
Revisions of previous quantity estimates, estimated      timing of development and other		648		13,708		14,356		(7,439)
Sales/disposition of reserves in place		—		—		—		(118,104)
Other		258		4,360		4,618		—
Accretion of discount		241		1,842		2,083		8,647
End of period	$	8,010	$	71,959	$	79,969	$	7,223

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

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 consolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. We do not have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

Our wholly-owned subsidiaries include Hawaii Pacific Energy, LLC (“Hawaii Pacific Energy”)  which acquired all of the outstanding membership interests of HIE on September 25, 2013 (see Note 4– Acquisitions and Dispositions), Par Piceance Energy, LLC, which owns our investment in Piceance Energy (see Note 3 – Investment in Piceance Energy) and Texadian, which we acquired on December 31, 2012 (see Note 4 – Acquisitions and Dispositions). Certain amounts from prior periods have been reclassified to conform to the current presentation.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include fair value of assets and liabilities recorded in connection with the application of fresh-start reporting or acquisitions, natural gas and oil reserves, depletion and impairment of natural gas and oil properties, income taxes and the valuation allowances related to deferred tax assets, bad debts,  derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.

Fresh-Start Reporting and the Effects of the Plan

Certain companies qualify for fresh-start reporting in connection with their emergence from bankruptcy. Fresh-start reporting is appropriate on the emergence from bankruptcy if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. We met these requirements on August 31, 2012 and adopted fresh-start reporting resulting in the creation of a new reporting entity.

The bankruptcy court issued a confirmation order approving our plan of reorganization (the “Plan”) on August 15, 2012 and we met the requirements of the Plan on August 31, 2012. Under the requirements of fresh-start reporting, we have adjusted our assets and liabilities to their estimated fair values as of August 31, 2012 in conformity with the guidance for the acquisition method of accounting for business combinations. The net effect of all fresh-start adjustments, including the effects of implementing the plan, resulted in a gain of approximately $154 million, which is reflected in the 2012 Predecessor Period. The application of the fresh-start reporting provisions created a new reporting entity having no retained earnings nor accumulated deficit.

Our fresh-start adjustments consisted primarily of (i) estimates of the fair value of our minority interest in Piceance Energy and (ii) of the fair value of our remaining existing fixed assets and liabilities. A description of the adjustments and amounts is provided in Note 19 – Reorganization under Chapter 11, Fresh-Start Reporting and the Effects of the Plan.

 

Cash and Cash Equivalents

Cash and cash equivalents consist of demand deposits and funds invested in highly liquid short-term investments with original maturities of three months or less.

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.

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 collectability and establish or adjust our allowance as necessary using the specific identification method. As of December 31, 2013 and 2012, we had no significant allowance for doubtful accounts. 

Refined Product Exchanges

We enter into exchange and supply contracts whereby we agree to deliver a particular quantity and quality of refined products at a specified location and date to a particular counterparty and to receive from the same counterparty a particular quantity and quality of refined products at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions with the exception of associated grade or location differentials that are settled in cash each month. These transactions are not recorded as revenue because they involve the exchange of refined product inventories held for sale in the ordinary course of business to facilitate sales to customers. The exchange transactions are recognized at the carrying amount of the inventory transferred plus or minus any cash settlement due to grade or location differentials.

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.

HIE 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 HIE’s storage tanks governed by a storage agreement. Legal title to the crude oil passes to HIE at the tank outlet. After processing, Barclays takes title to the refined products when the refined products enter the tanks which are then stored in HIE’s storage tanks until sold to HIE’s 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.

Investment in Unconsolidated Affiliate

We account for our investment in unconsolidated affiliate using the equity method as we have the ability to exert significant influence, but do not control the operating and financial policies. Our proportionate share of net income (loss) of these entities is recorded as income (loss) from unconsolidated affiliates in the consolidated statements of operations. Investment in unconsolidated affiliate is reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

At December 31, 2013 and 2012, our investment in unconsolidated affiliates consisted of our ownership interest in Piceance Energy (see Note 3 - Investment in Piceance Energy.)

Property, Plant and Equipment (Other than Natural Gas and Oil Properties)

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
Logistic	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 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 with significant acquisition costs 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 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.

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. 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 or when circumstances indicate that impairment may exist. 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.

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, distribution and marketing business’ refinery and 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 depreciation, depletion and amortization expense 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 statements of consolidated 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 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.

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 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 it will not net settle.  Should we not designate a contract as a normal purchase or normal sale then 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, 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. As of December 31, 2012, we did not elect this exemption for our open contracts which were settled in the first quarter of 2013.

 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.

As a part of the Plan of Reorganization, we issued warrants (see Note 10 - Debt) 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 reported in change in value of common stock warrants and loss on derivative instruments, net respectively, on our consolidated statement of operations.

Accrued Settlement Claims

We accrued an estimate of the settlement liability relating to claims resulting from our bankruptcy (See Note 13 - Commitments and Contingencies). Professional fees relating to the settlement of bankruptcy claims are charged to earnings in the period incurred.

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 2010, 2011, and 2012. 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 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. These transactions include sale and purchase transactions entered into with the same counterparty that are deemed to be in contemplation with one another.

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, 2013 and 2012, 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 rail cars. 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.

Refining, Distribution and Marketing. 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 statements of consolidated operations, while the related transportation costs are included in cost of sales. Federal excise and state motor fuel taxes, which are remitted to governmental agencies through our refining segment and collected from customers in our retail segment, are included in both revenues and cost of sales in our statements of consolidated operations.

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 (see Note 16 - Loss Per Share). 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 our functional currency (“U.S. $”). 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) in the accompanying consolidated statement of operations in the period in which the currency exchange rates change.  

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Intangible assets (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
2014	$ 3,571
2015	2,471
2016	2,151
2017	908
2018	258
Thereafter	1,811
Total	$ 11,170	$ 8,809

XML

Loss Per Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Schedule Of Computation Of Basic And Diluted Earnings Per Share [Table Text Block]

The following table sets forth the computation of basic and diluted loss per share (in thousands, except per share amounts):

	Successor				Predecessor
			September 1		January 1
	Year Ended		through		through
	December 31,		December 31,		August 31,
	2013		2012		2012
Net loss attributable to common stockholders	$	(70,621)	$	(8,839)	$	(45,437)
Basic weighted-average common shares     outstanding		19,740		15,734		28,841
Add: dilutive effects of stock options and     unvested stock grants (1)		—		—		—
Diluted weighted-average common stock outstanding		19,740		15,734		28,841
Basic loss per common share attributable to     common stockholders:
Net loss (1)	$	(3.57)	$	(0.56)	$	(1.57)
Diluted loss per common share attributable to     common stockholders:
Net loss (1)	$	(3.57)	$	(0.56)	$	(1.57)

________________________________________________________

^{(1) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Therefore, we have utilized the basic weighted-average common shares outstanding to calculate both basic and diluted loss per share for all parties presented.}

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]

Weighted average potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following (in thousands):

	Successor		Predecessor
		Period from	Period from
		September 1	January 1
	Year Ended	through	through
	December 31,	December 31,	August 31,
	2013	2012	2012
Stock issuable upon conversion of convertible notes	—	—	379
Stock options	—	—	150
Non-vested restricted stock	523	—	558
Total potentially dilutive securities	523	—	1,087

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Information Regarding Proved Oil and Gas Reserves

12 Months Ended

Dec. 31, 2013

Oil and Gas Property [Abstract]

Oil And Gas Properties [Text Block]

Note 22 - 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 the company’s oil and natural gas reserves and present values as of December 31, 2013 and 2012,  and August 31, 2012 were prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers.  

A summary of changes in estimated quantities of proved reserves for the year ended December 31, 2013 and for respective periods in 2012 is as follows:

	Gas	Oil	NGLS	Total
	(MMcf)	(MBbl)	(MBb1)	(MMcfe) (5)
Company:
Estimated Proved Reserves: Balance at January 1, 2012     (Predecessor) (1)	87,209	494	—	90,173
Revisions of quantity estimate	—	85	—	512
Sale/disposition of properties (2)	(82,357)	(235)	—	(83,770)
Production	(4,852)	(67)	—	(5,256)
Estimated Proved Reserves: Balance at August 31, 2012     (Successor)	—	277	—	1,659
Revisions of quantity estimate	456	31	—	643
Production	(10)	(22)	—	(139)
Estimated Proved Reserves: Balance at December 31, 2012     (Successor)	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     (Successor)	662	236	—	2,078
Company’s Share of Piceance Energy:
Estimated Proved Reserves: Balance at September 1, 2012	—	—	—	—
Transfer from investees (3)	83,915	560	4,228	112,639
Revisions of quantity estimate	8,053	41	387	10,621
Extensions and discoveries	32,073	236	1,778	44,151
Production	(1,391)	(6)	(48)	(1,711)
Estimated Proved Reserves: Balance at December 31, 2012	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	186,597	584	7,401	234,509
Total Estimated Proved Reserves: Balance at December 31, 2013	187,259	820	7,401	236,587
Proved developed reserves
December 31, 2012	158	286	—	1,875
December 31, 2012—Company Share of Piceance Energy	48,680	237	2,253	63,617
Total December 31, 2012	48,838	523	2,253	65,492
Proved undeveloped reserves
December 31, 2012	288	—	—	288
December 31, 2012—Company Share of Piceance Energy	73,970	594	4,092	102,083
Total December 31, 2012	74,258	594	4,092	102,371
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

	CIG per Mbtu		WTI per Bbl
Base pricing, before adjustments for contractual     differentials: (4)
August 31, 2012	$	2.75	$	90.85
December 31, 2012	$	2.56	$	91.21
December 31, 2012 – Piceance	$	2.56	$	91.21
December 31, 2013	$	3.53	$	96.91
December 31, 2013 – Piceance	$	3.53	$	96.91

_________________________________________________________

⁽¹⁾ At January 1, 2012, gas is based on 70,982 MMcf of natural gas and 4,057 MBbl of natural gas liquids, with liquids converted to gas using a ratio of 4 Mcf to 1 barrel.

⁽²⁾ On August 31, 2012, substantially all of the reserves of the company were transferred to Piceance Energy in exchange for a 33.34% equity ownership interest (See Note 3 - Investment in Piceance Energy).

⁽³⁾ On August 31, 2012, certain reserves held by Delta Petroleum and by Laramie were transferred to Piceance Energy in exchange for a 33.34% and a 66.66% equity ownership interest, respectively (See Note 3 - Investment in Piceance Energy).

⁽⁴⁾ 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.

⁽⁵⁾ MMcfe is based on a ratio of 6 Mcf to 1 barrel.

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.

	Successor				Predecessor
	December 31,				August 31,
	2013		2012		2012
	(in thousands)				(in thousands)
Company:
Future net cash flows	$	26,861	$	30,444	$	28,691
Future costs:
Production		21,999		20,596		19,973
Development and abandonment		319		319		319
Income taxes1		—		—		—
Future net cash flows		4,543		9,529		8,399
10% discount factor		(1,006)		(1,519)		(1,176)
Standardized measure of discounted future net cash      flows	$	3,537	$	8,010	$	7,223
Company’s Share of Piceance Energy:
Future net cash flows	$	984,205	$	568,706
Future costs:
Production		430,506		199,277
Development and abandonment		234,905		154,054
Income taxes1		—		—
Future net cash flows		318,794		215,375
10% discount factor		(229,469)		(143,416)
Standardized measure of discounted future net      cash flows	$	89,325	$	71,959
Total Company and Company share of equity      investee in the standardized measure of      discounted future net revenues	$	92,862	$	79,969

________________________________________________

¹            No income tax provision is included in the standardized measure calculation shown above as the company does 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.

The principal sources of changes in the standardized measure of discounted net cash flows for the year ended December 31, 2013 and for the respective periods during 2012 are as follows (in thousands): 

	Successor
	December 31,		Company Share of Piceance Energy December 31,		Total
	2013		2013		2013
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

	Successor						Predecessor
	Period from September 1, through December 31,		Company Share of Piceance Energy September 1, through December 31,		Total		January 1, through August 31,
	2012		2012		2012		2012
Beginning of the year							$	129,695
Beginning of the period	$	7,223	$	—	$	7,223		—
Transfer from investees		—		55,253		55,253		—
Sales of oil and gas production during the period,      net of production costs		(456)		(3,639)		(4,095)		(5,954)
Net change in prices and production costs		(667)		(139)		(806)		378
Changes in estimated future development costs		—		5		5		—
Extensions, discoveries and improved recovery		763		569		1,332		—
Revisions of previous quantity estimates, estimated      timing of development and other		648		13,708		14,356		(7,439)
Sales/disposition of reserves in place		—		—		—		(118,104)
Other		258		4,360		4,618		—
Accretion of discount		241		1,842		2,083		8,647
End of period	$	8,010	$	71,959	$	79,969	$	7,223

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Disclosures About Capitalized Costs, Costs Incurred

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Capitalized Costs Relating To Oil And Gas Producing Activities Disclosure [Text Block]

Note 21- Disclosures About Capitalized Costs, Costs Incurred (Unaudited)

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

	Successor				Predecessor
	December 31, 2013		December 31, 2012		August 31, 2012
Company:
Unproved properties	$	—	$	—	$	84
Proved properties		4,949		4,804		759,755
		4,949		4,804		759,839
Accumulated depreciation and depletion		(1,868)		(337)		(642,172)
	$	3,081	$	4,467	$	117,667
Company’s Share of Piceance Energy:
Unproved properties	$	15,763	$	16,180
Proved properties		168,378		134,638
		184,141		150,818
Accumulated depreciation and depletion		(38,452)		(2,808)
	$	145,689	$	148,010

(1) The capitalized cost amounts presented are as of August 31, 2012 for the Predecessor and exclude adjustments resulting from the plan or reorganization and fresh-start reporting (see Note 19 - Reorganization Under Chapter 11, Fresh-Start Reporting and the Effects of the Plan).  

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

	Successor				Predecessor
	Year Ended December 31, 2013		Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012
Company:
Development costs incurred on proved undeveloped     reserves	$	—	$	—	$	1,613
Development costs—other		142		—		—
Total	$	142	$	—	$	1,613
Company’s Share of Piceance Energy:
Unproved properties acquisition costs	$	—	$	206
Proved properties acquisition costs (1)		—		32,519
Development costs—other		6,380		291
Total	$	6,380	$	33,016

_______________________________________________________ 

(1) Amount represents our share of proved oil and natural gas property acquired at inception of the formation of Piceance Energy, of which $24.2 million relates to oil and natural gas properties purchased from Delta contemplated as part the emergence from bankruptcy and $8.3 million relates oil and natural gas properties purchased from Laramie.

At December 31, 2011, the company had $8,770 of suspended exploratory well cost subject to evaluation. Upon the emergency from Bankruptcy on August 31, 2012 all capitalized oil and natural gas property costs, including suspended exploratory well cost, were transferred to Piceance in exchange for cash and a 33.34% equity interest in Piceance. For the period from September 1, 2012 through December 31, 2012 and for the year ended December 31, 2013 neither the company 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 December 31, 2012 and 2013 that were being evaluated.

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

	Successor				Predecessor
	Year Ended December 31, 2013		September 1 through December 31, 2012		January 1 through August 31, 2012
Company:
Revenue:
Oil and gas revenues	$	7,739	$	2,144	$	23,079
Expenses:
Production costs		5,696		1,688		16,980
Depletion and amortization		1,593		370		16,041
Exploration		—		—		2
Abandoned and impaired properties		—		—		151,347
Results of operations of oil and gas producing activities	$	450	$	86	$	(161,291)
Company’s share of Piceance Energy:
Revenue:
Oil and gas revenues	$	20,364	$	6,464
Expenses:
Production costs		9,885		3,033
Depletion and amortization		8,855		2,808
Results of operations of oil and gas producing activities	$	1,624	$	623
Total Company and Piceance Energy income from     operations of oil and gas producing activities	$	2,074	$	709

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Related Party Transaction (Details Textual)	12 Months Ended
	Dec. 31, 2013
Travel And Out Of Pocket Expense Description	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

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Acquisitions and Dispositions (Details Textual) (USD $)	4 Months Ended	12 Months Ended		8 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013 Assets Held-for-sale [Member]	Aug. 31, 2012 Piceance Energy [Member]	Dec. 31, 2012 Texadian Energy, Inc.	Dec. 31, 2013 Hawaii Independent Energy LLC [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross					$ 14,000,000	$ 75,000,000
Business acquisition purchase price allocation working capital					3,000,000
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Costs					17,000,000
Payments To Acquire Businesses Net Of Cash Acquired	17,439,000	559,279,000				40,000,000
Funding Of Acquisition From Supply And Exchange Agreements						378,200,000
Significant Acquisitions and Disposals, Terms						The earnout payments, if any, are to be paid annually following each of the three calendar years beginning January1, 2014 through the year ending December31, 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.
Debtor Reorganization Items, Impairment Loss				151,300,000
Proceeds from Sale of Productive Assets, Total			2,900,000
Gain (Loss) on Disposition of Property Plant Equipment, Total			50,000
Business Combination, Consideration Transferred, funds received from subsidiary		1,300,000
Business Combination, Acquisition Related Costs					556,000	7,000,000
Business Combination, funded for overhaul of co-generation turbine						$ 24,300,000

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Summarized financial information concerning reportable segments consists of the following (in thousands):

For the year ended December 31, 2013	Refining, Distribution and Marketing		Natural Gas and Oil Operations		Commodity Marketing and Logistics		Corporate and Other		Total
Sales and operating revenues	$	778,126	$	7,739	$	100,149	$	—	$	886,014
Depreciation, depletion, amortization     and accretion		2,267		1,686		2,009		20		5,982
Operating income (loss)		(19,318)		246		9,126		(29,367)		(39,313)
Loss from unconsolidated affiliate										(2,941)
Interest expense and financing costs, net										(19,471)
Other income (expense)										808
Change in value of common stock warrants										(10,114)
Gain on derivative instruments										410
Loss before income taxes										(70,621)
Income tax benefit										—
Net loss									$	(70,621)
Capital expenditures, including acquisitions	$	567,332	$	471	$	(1,300)	$	544	$	567,047

For the period from September 1 through December 31, 2012, expenditures for long term assets, including goodwill and other intangible assets by segment were as follows (in thousands):

	Natural Gas and Oil Operations		Commodity Marketing and Logistics		Corporate and Other		Total
Capital expenditures, including acquisitions	$	415	$	17,439	$	—	$	17,854

Schedule of Segment Reporting Information, by Segment, Financial Position [Table Text Block]

Total assets by segment were as follows (in thousands):

	Refining, Distribution  and Marketing		Natural Gas  and Oil  Operations		Commodity  Marketing and Logistics		Corporate and Other		Total
At December 31, 2013	$	655,712	$	109,316	$	52,048	$	10,009	$	827,085
At December 31, 2012	$	—	$	116,034	$	62,754	$	10,794	$	189,582

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Organization Consolidation And Presentation Of Financial Statements Disclosure, Policy [Policy Text Block]

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Par Petroleum Corporation and its consolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. We do not have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

Our wholly-owned subsidiaries include Hawaii Pacific Energy, LLC (“Hawaii Pacific Energy”)  which acquired all of the outstanding membership interests of HIE on September 25, 2013 (see Note 4– Acquisitions and Dispositions), Par Piceance Energy, LLC, which owns our investment in Piceance Energy (see Note 3 – Investment in Piceance Energy) and Texadian, which we acquired on December 31, 2012 (see Note 4 – Acquisitions and Dispositions). Certain amounts from prior periods have been reclassified to conform to the current presentation.

Use Of Estimates, Policy [Policy Text Block]

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include fair value of assets and liabilities recorded in connection with the application of fresh-start reporting or acquisitions, natural gas and oil reserves, depletion and impairment of natural gas and oil properties, income taxes and the valuation allowances related to deferred tax assets, bad debts,  derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.

Reorganization, Policy [Policy Text Block]

Fresh-Start Reporting and the Effects of the Plan

Certain companies qualify for fresh-start reporting in connection with their emergence from bankruptcy. Fresh-start reporting is appropriate on the emergence from bankruptcy if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. We met these requirements on August 31, 2012 and adopted fresh-start reporting resulting in the creation of a new reporting entity.

The bankruptcy court issued a confirmation order approving our plan of reorganization (the “Plan”) on August 15, 2012 and we met the requirements of the Plan on August 31, 2012. Under the requirements of fresh-start reporting, we have adjusted our assets and liabilities to their estimated fair values as of August 31, 2012 in conformity with the guidance for the acquisition method of accounting for business combinations. The net effect of all fresh-start adjustments, including the effects of implementing the plan, resulted in a gain of approximately $154 million, which is reflected in the 2012 Predecessor Period. The application of the fresh-start reporting provisions created a new reporting entity having no retained earnings nor accumulated deficit.

Our fresh-start adjustments consisted primarily of (i) estimates of the fair value of our minority interest in Piceance Energy and (ii) of the fair value of our remaining existing fixed assets and liabilities. A description of the adjustments and amounts is provided in Note 19 – Reorganization under Chapter 11, Fresh-Start Reporting and the Effects of the Plan.

Cash And Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

Cash and cash equivalents consist of demand deposits and funds invested in highly liquid short-term investments with original maturities of three months or less.

Cash And Cash Equivalents Restricted Cash And Cash Equivalents, Policy [Policy Text Block]

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.

Receivables Trade And Other Accounts Receivable Allowance For Doubtful Accounts, Policy [Policy Text Block]

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 collectability and establish or adjust our allowance as necessary using the specific identification method. As of December 31, 2013 and 2012, we had no significant allowance for doubtful accounts. 

Refined Product Exchanges Policy [Policy Text Block]

Refined Product Exchanges

We enter into exchange and supply contracts whereby we agree to deliver a particular quantity and quality of refined products at a specified location and date to a particular counterparty and to receive from the same counterparty a particular quantity and quality of refined products at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions with the exception of associated grade or location differentials that are settled in cash each month. These transactions are not recorded as revenue because they involve the exchange of refined product inventories held for sale in the ordinary course of business to facilitate sales to customers. The exchange transactions are recognized at the carrying amount of the inventory transferred plus or minus any cash settlement due to grade or location differentials.

Inventory, Policy [Policy Text Block]

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.

HIE 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 HIE’s storage tanks governed by a storage agreement. Legal title to the crude oil passes to HIE at the tank outlet. After processing, Barclays takes title to the refined products when the refined products enter the tanks which are then stored in HIE’s storage tanks until sold to HIE’s 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.

Investments In Unconsolidated Entities, Policy [Policy Text Block]

Investment in Unconsolidated Affiliate

We account for our investment in unconsolidated affiliate using the equity method as we have the ability to exert significant influence, but do not control the operating and financial policies. Our proportionate share of net income (loss) of these entities is recorded as income (loss) from unconsolidated affiliates in the consolidated statements of operations. Investment in unconsolidated affiliate is reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

At December 31, 2013 and 2012, our investment in unconsolidated affiliates consisted of our ownership interest in Piceance Energy (see Note 3 - Investment in Piceance Energy.)

Property Plant And Equipment, Policy [Policy Text Block]

Property, Plant and Equipment (Other than Natural Gas and Oil Properties)

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
Logistic	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.

Oil and Gas Properties Policy [Policy Text Block]

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 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 with significant acquisition costs 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 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.

Goodwill And Intangible Assets, Policy [Policy Text Block]

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. 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 or when circumstances indicate that impairment may exist. 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.

Asset Retirement Obligations, Policy [Policy Text Block]

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, distribution and marketing business’ refinery and 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 depreciation, depletion and amortization expense 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 statements of consolidated 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 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.

Environmental Costs, Policy [Policy Text Block]

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 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, Policy [Policy Text Block]

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 it will not net settle.  Should we not designate a contract as a normal purchase or normal sale then 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, 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. As of December 31, 2012, we did not elect this exemption for our open contracts which were settled in the first quarter of 2013.

 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.

As a part of the Plan of Reorganization, we issued warrants (see Note 10 - Debt) 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 reported in change in value of common stock warrants and loss on derivative instruments, net respectively, on our consolidated statement of operations.

Settlements, Policy [Policy Text Block]

Accrued Settlement Claims

We accrued an estimate of the settlement liability relating to claims resulting from our bankruptcy (See Note 13 - Commitments and Contingencies). Professional fees relating to the settlement of bankruptcy claims are charged to earnings in the period incurred.

Income Tax, Policy [Policy Text Block]

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 2010, 2011, and 2012. 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.

Share Based Compensation Option And Incentive Plans, Policy [Policy Text Block]

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 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, Policy [Policy Text Block]

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. These transactions include sale and purchase transactions entered into with the same counterparty that are deemed to be in contemplation with one another.

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, 2013 and 2012, 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 rail cars. 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.

Refining, Distribution and Marketing. 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 statements of consolidated operations, while the related transportation costs are included in cost of sales. Federal excise and state motor fuel taxes, which are remitted to governmental agencies through our refining segment and collected from customers in our retail segment, are included in both revenues and cost of sales in our statements of consolidated operations.

Earnings Per Share, Policy [Policy Text Block]

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 (see Note 16 - Loss Per Share). 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 And Translations, Policy [Policy Text Block]

Foreign Currency Transactions

We may, on occasion, enter into transactions denominated in currencies other than our functional currency (“U.S. $”). 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) in the accompanying consolidated statement of operations in the period in which the currency exchange rates change.  

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Property Plant And Equipment Estimated Useful Life [Table Text Block]

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
Logistic	3 to 30
Retail	14 to 18
Corporate	3 to 7
Software	3

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Overview

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

Note 1 - Overview

We are a diversified energy holding company based in Houston, Texas (OTCQB:PARR). We were created through the successful reorganization of Delta Petroleum in August 2012. The reorganization converted approximately $265 million of unsecured debt to equity and allowed us to preserve significant tax attributes. Currently, we operate in three segments: (i) refining, distribution and marketing, (ii) natural gas and oil operations and (iii) commodity marketing and logistics operations.

 Our refining, distribution and marketing segment consists of a refinery in Kapolei, Hawaii. The refinery produces ultra-low sulfur diesel, gasoline, jet fuel, marine fuel and other associated refined products primarily for consumption in Hawaii. Our refinery logistics assets include refined products terminals, pipelines, a single point mooring and other associated logistics assets. In addition, we distribute products though 31 branded retail outlets located across the islands of Oahu, Maui and Hawaii. The refining, distribution and marketing segment was established through the acquisition of Hawaii Independent Energy, LLC (“HIE”) (formerly known as Tesoro Hawaii, LLC (“Tesoro Hawaii”)) in September 2013 for approximately $75 million in cash, plus net working capital and inventories and certain contingent earn out payments of up to approximately $40 million (the “HIE Acquisition”).  As part of the purchase price, we also funded $24.3 million of start-up expenses and for a major overhaul of a co-generation turbine used at the refinery prior to closing.  

Our natural gas and oil operations consist primarily of a 33.34% interest in Piceance Energy, LLC (“Piceance Energy”) (Note 3 - Investment in Piceance Energy). Piceance Energy is a joint venture with Laramie Energy II, LLC (“Laramie”), who owns the remaining interest and manages the day to day operations of the joint venture. Laramie is a Denver-based company primarily focused on finding and developing natural gas reserves from unconventional gas reservoirs within the Rocky Mountain region. Piceance Energy was formed and capitalized in August 2012 when we and Laramie Energy contributed oil and natural gas assets, surface real estate, and other related assets located in the Piceance Basin geological province of Colorado to the joint venture entity.

Our commodity marketing and logistics segment focuses on sourcing, marketing, transportation and distribution of crude oil and refined products. Our logistics capability consists of historical pipeline shipping status, a rail car 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, the Gulf Coast, and the East Coast regions of the U.S. The commodity marketing and logistics operations segment was established through the acquisition of Texadian Energy, Inc. (“Texadian”) (formerly known as SEACOR Energy, Inc.) in December 2012 for approximately $14 million in cash, plus approximately $3 million in working capital.

As a result of these transactions, our results of operations for any period after December 31, 2013 will not be comparable to any prior period.

On January 23, 2014, we amended and restated 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. 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 outstanding prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis, unless otherwise noted. No adjustments have been made to the share or per share amounts of our Predecessor (see Note 20 - Subsequent Events).

To generate earnings and cash flows from operations, the Company’s refining, distribution and marketing segment is primarily dependent upon processing crude oil and selling refined petroleum products at margins sufficient to cover fixed and variable costs and other expenses. Crude oil and refined petroleum products are commodities and factors largely out of the Company’s control can cause prices to vary over time.

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Investment in Piceance Energy (Tables)

12 Months Ended

Dec. 31, 2013

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments [Table Text Block]

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

			September 1
	Year Ended		through
	December 31, 2013		December 31, 2012
Beginning balance	$	104,434	$	105,344
Loss from unconsolidated affiliates		(3,516)		(1,325)
Accretion of basis difference		575		—
Capitalized drilling costs obligation paid		303		415
Ending balance	$	101,796	$	104,434

Equity Method Investees Financial Information [Table Text Block]

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

	December 31, 2013		December 31, 2012
Assets
Current assets	$	5,901	$	6,275
Non-current assets		454,402		460,991
Current liabilities		(13,040)		(11,826)
Non-current liabilities		(96,738)		(94,369)

	Year Ended		September 1 through
	December 31, 2013		December 31, 2012
	100%		100%
Oil, natural gas and natural gas liquids     revenues	$	61,091	$	19,391
Loss from operations		(6,765)		(2,095)
Net loss		(10,546)		(3,975)

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Commitments and Contingencies (Details) (USD $) In Thousands, unless otherwise specified	0 Months Ended		4 Months Ended		12 Months Ended
	Aug. 31, 2012 Count		Dec. 31, 2012 Count		Dec. 31, 2013 Count
Commitment And Contingencies [Line Items]
Number of claims filed	112
Amount of claims filed	$ 73,730
Number of claim settled			25		59
Amount of claim settled			6,600		26,906
Amount of claim settled in cash			259		5,383
Amount of claim settled stock			20		209
Number of remaining claim to be resolved			87		28
Amount of remaining claim to be resolved			67,130		40,224
U S Government [Member]
Commitment And Contingencies [Line Items]
Number of claims filed	3
Amount of claims filed	22,364
Number of claim settled			0		1
Amount of claim settled			0		0
Amount of claim settled in cash			0		0
Amount of claim settled stock			0		0
Number of remaining claim to be resolved			3		2
Amount of remaining claim to be resolved			22,364		22,364
Former Employee Claims [Member]
Commitment And Contingencies [Line Items]
Number of claims filed	32
Amount of claims filed	16,380
Number of claim settled			13		19
Amount of claim settled			3,685		12,695
Amount of claim settled in cash			230		340
Amount of claim settled stock			20		162
Number of remaining claim to be resolved			19		0
Amount of remaining claim to be resolved			12,695		0
Macquarie Capital Incorporated [Member]
Commitment And Contingencies [Line Items]
Number of claims filed	1
Amount of claims filed	8,672
Number of claim settled			0		1
Amount of claim settled			0		8,672
Amount of claim settled in cash			0		2,500
Amount of claim settled stock			0		0
Number of remaining claim to be resolved			1		0
Amount of remaining claim to be resolved			8,672		0
Swann And BuzzardCreek RoyaltyTrust [Member]
Commitment And Contingencies [Line Items]
Number of claims filed	1
Amount of claims filed	3,200
Number of claim settled			0		1
Amount of claim settled			0		3,200
Amount of claim settled in cash			0		2,000
Amount of claim settled stock			0		0
Number of remaining claim to be resolved			1		0
Amount of remaining claim to be resolved			3,200		0
Other Various Claims [Member]
Commitment And Contingencies [Line Items]
Number of claims filed	75	[1]
Amount of claims filed	23,114	[1]
Number of claim settled			12	[1]	37	[1]
Amount of claim settled			2,915	[1]	2,339	[1]
Amount of claim settled in cash			29	[1]	543	[1]
Amount of claim settled stock			0	[1]	47	[1]
Number of remaining claim to be resolved			63	[1]	26	[1]
Amount of remaining claim to be resolved			$ 20,199	[1]	$ 17,860	[1]

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

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Schedule Of Reorganization Distributions To Satisfy Allowed Claims [Table Text Block]

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

	Emergence-Date August 31, 2012				From Emergence-Date through December 31, 2012
											Remaining Filed
	Filed Claims				Settled Claims						Claims
								Consideration
	Count		Amount		Count	Amount		Cash		Stock	Count	Amount
U.S. Government Claims		3	$	22,364	—	$	—	$	—	—	3	$	22,364
Former Employee Claims		32		16,380	13		3,685		230	20	19		12,695
Macquarie Capital (USA) Inc.		1		8,672	—		—		—	—	1		8,672
Swann and BuzzardCreek    RoyaltyTrust		1		3,200	—		—		—	—	1		3,200
Other Various Claims*		75		23,114	12		2,915		29	—	63		20,199
Total		112	$	73,730	25	$	6,600	$	259	20	87	$	67,130

	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.

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

Minimum annual lease payments including interest, for capital leases are as follows (in thousands):

2014	$	382
2015		382
2016		382
2017		382
2018		420
Thereafter		420
Total minimum lease payments		2,368
Less amount representing interest		634
Total minimum rental payments	$	1,734

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

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):

2014	$	22,724
2015		13,277
2016		12,362
2017		10,375
2018		9,244
Thereafter		25,614
Total minimum rental payments	$	93,596

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Investment in Piceance Energy (Details Textual) (USD $)	4 Months Ended	12 Months Ended				12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013 Piceance Energy [Member]	Dec. 31, 2012 Piceance Energy [Member]	Aug. 31, 2012 Piceance Energy [Member]	Dec. 31, 2013 Parent Company [Member] Piceance Energy [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment Ownership Percentage			33.34%		33.34%
Equity Method Investments, Additional Capital Contribution			$ 60,000,000			$ 20,000,000
Line Of Credit Facility Maximum Borrowing Capacity			400,000,000
Line Of Credit Facility Current Borrowing Capacity			120,000,000
Line Of Credit Facility Amount Outstanding			90,200,000		100,000,000
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity			15,100,000	15,900,000
Lack Of Control And Marketability Discounts Amortization Term		15 years
Depreciation, Depletion, Amortization and Accretion Expense	401,000	5,982,000	26,600,000	8,500,000
Losses on derivative instruments			$ 770,000	$ 917,000

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Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	Aug. 31, 2012
Piceance Energy [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Investment in Piceance Energy	$ 105,300
Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Proved	4,587	[1],[2]
Fair Value, Measurements, Nonrecurring [Member] | Frac tanks [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Other assets	1,400	[3]
Fair Value, Measurements, Nonrecurring [Member] | Compressors [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Other assets	2,800	[3]
Fair Value, Measurements, Nonrecurring [Member] | Miscellaneous [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Other assets	39	[4]
Fair Value, Measurements, Nonrecurring [Member] | Piceance Energy [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Investment in Piceance Energy	$ 105,344	[5]

[1] Certain proved property was valued using the cost valuation technique. A significant input in this measurement was the estimated cost of the properties. A change in that estimated cost would be directly correlated to change in the estimated fair value of the property. We consider this to be a level 3 fair value measurement.

[2] The estimated fair value of our Point Arguello Unit offshore California was valued using a market valuation technique based on standalone bids received by third-parties during the sale process. We consider this to be a level 2 fair value measurement.

[3] The estimated fair value of our frac tanks and compressor units was valued using a market valuation technique which was based on published listings of similar equipment or standalone bids received by third-parties. We consider these to be level 2 fair value measurements.

[4] Miscellaneous assets (assets that we were unable to value using the income or market valuation techniques) were valued using the cost valuation technique. We consider this to be a level 3 fair value measurement.

[5] The estimated fair value of our investment in Piceance Energy was based on its enterprise value and uses various valuation techniques including (i) an income approach based on proved developed reserves’ future net income discounted back to net present value based on the weighted average cost of capital for comparable independent oil and natural gas producers, and (ii) a market multiple approach. Proved property was valued using the income approach. A discounted cash flow model was prepared based off of an independent reserve report with a discount rate of 10% applied to proved developed producing reserves, 15% to proved developed non-producing reserves and 20% to proved undeveloped reserves. The prices for oil and natural gas were forecasted based on NYMEX strip pricing adjusted for basis differentials. For the market multiple approach, we reviewed the transaction values of recent similar asset transactions and compared the purchase price per Mcfe of proved developed reserves and purchase price per Mcfe per day of net equivalent production of those transactions to the independent reserve report. Unproved acreage was valued using a cost approach based on recent sales of acreage in the area. Based on these valuations, the equity value of our 33.34% interest in Piceance Energy was estimated to be approximately $105.3 million on the Emergence date. We consider this to be a Level 3 fair value measurement.

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 38,061	$ 6,185
Restricted cash	802	23,970
Trade accounts receivable	122,913	17,730
Inventories	389,075	10,466
Prepaid and other current assets	7,522	1,575
Total current assets	558,373	59,926
Property and equipment
Property, plant and equipment	107,623	1,415
Proved oil and gas properties, at cost, successful efforts method of accounting	4,949	4,804
Total property and equipment	112,572	6,219
Less accumulated depreciation, depletion and amortization	(3,968)	(373)
Property and equipment, net	108,604	5,846
Long-term assets
Investments in unconsolidated affiliate	101,796	104,434
Intangible assets, net	11,170	8,809
Goodwill	20,603	7,756
Assets held for sale	0	2,800
Other long-term assets	26,539	11
Total assets	827,085	189,582
Current liabilities
Current maturities of long-term debt	3,250	35,000
Obligations under supply and exchange agreements	390,839	0
Accounts payable	28,870	25,329
Other accrued liabilities	31,956	981
Accrued settlement claims	3,793	8,667
Total current liabilities	458,708	69,977
Long-term liabilities
Long-term debt	94,030	7,391
Derivative liabilities	17,336	10,945
Long-term capital lease obligations	1,526	0
Deferred tax liability	216	0
Contingent consideration liability	11,980	0
Other liabilities	6,473	512
Total liabilities	590,269	88,825
Commitments and contingencies (Note 13)
Stockholders' Equity
Preferred stock, $0.01 par value: 3,000,000 shares authorized, none issued	0	0
Common stock, $0.01 par value; 500,000,000 shares and 300,000,000 shares authorized at December 31, 2013 and 2012, respectively, 30,151,000 shares and 15,008,092 shares issued at December 31, 2013 and 2012, respectively	301	150
Additional paid-in capital	315,975	109,446
Accumulated deficit	(79,460)	(8,839)
Total stockholders' equity	236,816	100,757
Total liabilities and stockholders' equity	$ 827,085	$ 189,582

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Reorganization Under Chapter 11, Fresh-Start Reporting and the Effects of the Plan (Tables)

12 Months Ended

Dec. 31, 2013

Reorganizations [Abstract]

Schedule Of Reorganization Items And Fresh Start Accounting [Table Text Block]

The following condensed consolidated balance sheet presents the implementation of the Plan and the adoption of fresh-start reporting as of the Effective Date. Reorganization adjustments have been recorded within the condensed consolidated balance sheet to reflect the effects of the Plan, including discharge of liabilities subject to compromise and the adoption of fresh-start reporting.

		August 31, 2012
				Plan of			Fresh Start
				Reorganization			Reporting
		Predecessor		Adjustments			Adjustments			Successor
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$	1,954	$	74,167	(a)	$			$	4,882
				(45,035)	(c)
				(24,204)	(d)
				(2,000)	(e)
Trust assets		—		3,446	(e)					3,446
Restricted cash		—		20,359	(d)					20,359
Trade accounts receivable, net		3,708		(1,727)	(a)		(1,981)	(g)		—
Prepaid assets		4,777					(4,777)	(g)		—
Prepaid reorganization costs		1,326					(1,326)	(g)		—
Total current assets		11,765								28,687
Property and equipment
Oil and gas properties
Unproved		84					(84)	(g)		—
Proved		759,755		(740,392)	(a)		(14,776)	(g)		4,587
Land		4,000		(4,000)	(a)					—
Other		73,021		(47,493)	(a)		(21,289)	(g)		4,239
Total property and equipment		836,860								8,826
Less accumulated depreciation and depletion		(642,172)		607,603	(a)		34,569	(g)		—
Property and equipment, net		194,688								8,826
Long-term assets:
Investments in unconsolidated affiliates		3,629		105,344	(a)		(3,629)	(g)		105,344
Other long-term assets		307					(253)	(g)		54
Total long-term assets		3,936								105,398
Total assets	$	210,389							$	142,911
LIABILITIES AND EQUITY
Current liabilities
Liabilities not subject to compromise
Debtor in possession financing	$	56,535		(56,535)	(c)				$	—
Accounts payable and other accrued liabilities		4,897								4,897
Other accrued liabilities		9,224		(2,685)	(b)					2,640
				(1,500)	(c)
				(3,845)	(d)
				1,446	(e)
Accrued reorganization and trustee expense		70,656								7,537
Liabilities subject to compromise
3 3/4% Senior notes		115,000		(115,000)	(b)					—
7% Senior convertible notes		150,000		(150,000)	(b)					—
Accounts payable and other accrued liabilities		17,203		(2,560)	(a)		(1,981)	(g)		12,336
				(3,526)	(d)		3,200	(g)
Total current liabilities		352,859								19,873
Long-term liabilities
Liabilities not subject to compromise
Long – term debt		—		6,335	(c)					6,335
Derivative liabilities		—		6,665	(c)					6,665
Asset retirement obligations		4,414		(3,938)	(a)					476
Total liabilities		357,273								33,349
Stockholders’ equity
Common stock		288		1,457	(b)		(288)	(f)		1,477
				20	(d)
Additional paid-in capital		1,643,285		100,084	(b)		288	(f)		108,085
				1,318	(d)		(1,636,890)	(h)
Retained earnings (accumulated deficit)		(1,790,457)		166,144	(b)		(14,765)	(g)		—
				2,188	(d)		1,636,890	(h)
Total stockholders’ equity (deficit)		(146,884)								109,562
Total liabilities and equity (deficit)	$	210,389							$	142,911

Notes to Plan of Reorganization and Fresh Start Accounting Adjustments

(a)	Reflects the contribution of certain of our oil and gas assets and related prepaid expenses and asset retirement obligations to Piceance Energy in exchange for cash and a 33.34% interest in Piceance Energy.
(b)	Reflects the extinguishment of secured debt in exchange for common stock of the Successor. On the Emergence Date, we issued 14,573,608 shares of our common stock and warrants to acquire 959,213 shares of our common stock to the holders of our secured debt or their affiliates. We estimated the fair value of our common stock to be $7.00 per share on the Emergence Date. Accordingly, we recorded a gain on the settlement of secured debt within Reorganization items of approximately $166.1 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
(c)	Reflects the Successor drawing $13 million under the Loan Agreement (see Note 10 - Debt) to repay amounts outstanding under the DIP Credit Facility with those proceeds and cash from contribution of assets to Piceance Energy.
(d)	Reflects the settlement of other claims with common stock of Successor and cash. On the Emergence Date, we issued 191,973 shares of our common stock to various creditors. We estimated the fair value of our common stock to be $7.00 per share on the Emergence Date. Accordingly, we recorded a gain on settlement of liabilities within Reorganization items of approximately $2.2 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
(e)	Reflects the funding of the Recovery Trusts (see Note 13 - Commitments and Contingencies).
(f)	Reflects the cancellation of Predecessor common stock.
(g)	Reflects adjustments to remaining assets due to fresh-start reporting. On the Emergence Date, we adjusted the carrying value of our remaining assets to their estimated fair values. As a result of these adjustments, we recorded a loss for changes in asset fair values due to fresh-start reporting adjustments within Reorganization items of approximately $14.8 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
(h)	Reflects the elimination of Predecessor’s accumulated deficit.

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Loss Per Share (Details 1) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended	4 Months Ended	12 Months Ended	4 Months Ended	12 Months Ended	4 Months Ended	12 Months Ended	8 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012 Stock Issuable upon Conversion of Convertible Notes [Member]	Dec. 31, 2013 Stock Issuable upon Conversion of Convertible Notes [Member]	Dec. 31, 2012 Stock Options and Warrants	Dec. 31, 2013 Stock Options and Warrants	Dec. 31, 2012 Non Vested Restricted Stock [Member]	Dec. 31, 2013 Non Vested Restricted Stock [Member]	Aug. 31, 2012 Predecessor [Member]	Aug. 31, 2012 Predecessor [Member] Stock Issuable upon Conversion of Convertible Notes [Member]	Aug. 31, 2012 Predecessor [Member] Stock Options and Warrants	Aug. 31, 2012 Predecessor [Member] Non Vested Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Total potentially dilutive securities	0	523	0	0	0	0	0	523	1,087	379	150	558

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY [Parenthetical] (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Payments of Stock Issuance Costs	$ 830

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Income Taxes (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2013
Income Taxes [Line Items]
Reduction in operating loss	$ 225,000,000
Net operating loss carryovers	1,300,000,000
Capital Loss carryovers	74,700,000
Alternative minimum tax credit carryovers	$ 800,000
Minimum [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration year	2027
Capital Loss carryovers, expiry year	2015
Maximum [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration year	2032
Capital Loss carryovers, expiry year	2016

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Asset Retirement Obligations (Details Textual) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2012
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation	$ 3,172	$ 512	$ 476
Piceance Energy [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation	$ 3,900

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Segment Information (Details Textual)	4 Months Ended
	Dec. 31, 2012
Number of businsess segment	2

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following is a reconciliation of our AROs (in thousands):

	Successor				Predecessor
			September 1		January 1
	Year Ended		through		through
	December 31, 2013		December 31, 2012		August 31, 2012
Asset retirement obligation –     beginning of period	$	512	$	476	$	3,799
Obligation acquired		2,601		—		—
Accretion expense		59		36		178
Change in estimate		—		—		437
Settlement upon transfer to     Piceance Energy		—		—		(3,938)
Asset retirement obligation –     end of period	$	3,172	$	512	$	476

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Supply and Exchange Agreements (Details Textual) (USD $)	4 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013
Shipping, Handling and Transportation Costs, Total		$ 3,700,000
Interest Expense, Total	1,056,000	19,471,000
Supply and Exchange Agreements [Member]
Interest Expense, Total		$ 1,400,000

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

Note 15 - Income Taxes

Under the Plan of Reorganization, our prepetition debt securities, primarily prepetition notes, were extinguished. Absent an exception, a debtor recognizes cancellation of debt income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. Tax regulations provide that a debtor in a bankruptcy case may exclude CODI from income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of our equity upon emergence from Chapter 11 bankruptcy proceedings, we were able to retain a significant portion of our NOLs and other “Tax Attributes” after reduction of the Tax Attributes for CODI realized on emergence from Chapter 11 and certain prior interest payments on debt converted to equity. Our NOLs have been reduced by approximately $225 million of CODI as a result of emergence from Chapter 11.

Pursuant to the Plan, on the Emergence Date, the existing equity interests of the Predecessor were extinguished. New equity interests were issued to creditors in connection with the terms of the Plan, resulting in an ownership change as defined under Section 382 of the Code. Section 382 generally places a limit on the amount of net operating losses and other tax attributes arising before the change that may be used to offset taxable income after the ownership change. We believe, however, 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 net operating losses; however the net operating losses are eliminated should another ownership change occur within two years. Our amended and restated certificate of incorporation places restrictions upon the ability of the equity interest holders to transfer their ownership in us. These restrictions are designed to provide us with the maximum assurance that another ownership change does not occur that could adversely impact our net operating loss carry forwards.

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, 2013 and 2012.

During the years ended December 31, 2013 and 2012, 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 2014 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:

	Successor				Predecessor
			Period from		Period from
			September 1		January 1
	Year Ended		through		through
	December 31,		December 31,		August 31,
	2013			2012		2012
Current:
U.S.—Federal	$	—	$	—	$	—
U.S.—State		(179)		—		—
Deferred:
U.S.—Federal		(14)		(2,757)		—
U.S.—State		193		—		—
Total	$	—	$	(2,757)	$	—

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: 

	Successor						Predecessor
				Period from			Period from
				September 1			January 1
	Year Ended			through			through
	December 31,			December 31,			August 31,
	2013			2012			2012
Federal statutory rate		(35.0)	%		(35.0)	%		(35.0)	%
State income taxes, net of federal benefit		0.1	%		—			—
Change in valuation allowance		21.7	%		(2.0)	%		(33.0)
Professional fees related to bankruptcy reorganization		—			8.0	%		17.0	%
Revenue from Wapiti Trust settlement		—			5.0	%		—
Cancellation of debt tax attribute reduction		—			—			51.0	%
Permanent Items		4.1	%
Provision to return adjustments		9.1	%		—			—
Actual income tax rate		—	%		(24.0)	%		—	%

Deferred tax assets (liabilities) are comprised of the following at December 31, 2013 and 2012 (in thousands):

	2013			2012
Deferred tax assets:
Net operating loss	$	540,867	$	450,195
Capital loss carry forwards		26,141		26,141
Property and equipment		34,683		23,045
Investment in Piceance Energy		32,138		45,172
Derivative instruments		—		1,498
Accrued bonuses		—		—
Trust liabilitiy		1,327		—
Other		1,183		1,506
Total deferred tax assets		636,339		547,557
Valuation allowance		(633,954)		(544,442)
Net deferred tax assets	$	2,385	$	3,115
Deferred tax liabilities:
Property and equipment	$	5	$	—
Texadian Energy intangibles		2,380		3,083
Prepaid insurance, marketable securities and other		—		32
State liabilities		216		—
Total deferred tax liabilities	$	2,601	$	3,115
Total deferred tax liability, net	$	(216)	$	—

We have net operating loss carryovers as of December 31, 2013 of $1.3 billion for federal income tax purposes. If not utilized, the tax net operating loss carryforwards will expire during 2027 through 2032. Our capital loss carryovers as of December 31, 2013 are $74.7 million. If not utilized, these carryovers will expire during 2015 and 2016. We also have Alternative Minimum Tax Credit Carryovers of $0.8 million. These credits do not expire; however, we must first generate regular taxable income before they can be used. We will not likely generate regular taxable income utilized our net operating loss carry over.

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Inventories (Tables)

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Schedule of Inventory, Current [Table Text Block]

The following is a summary of our inventory (in thousands):

								December 31,
	December 31, 2013							2012
				Supply and
		Titled		Exchange
		Inventory		Agreements		Total		Titled Inventory
Crude oil and feedstocks	$	—	$	146,158	$	146,158	$	10,466
Refined products and blend stock		67,532		161,554		229,086		—
Spare parts, materials and supplies, and merchandise		13,831		—		13,831		—
	$	81,363	$	307,712	$	389,075	$	10,466

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Segment Information (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Assets	$ 827,085	$ 189,582
Refining Distribution and Marketing [Member]
Assets	655,712	0
Natural Gas and Oil Operations [Member]
Assets	109,316	116,034
Commodity Marketing And Logistics [Member]
Assets	52,048	62,754
Corporate and Other [Member]
Assets	$ 10,009	$ 10,794

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Segment Information

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

Note 17 - Segment Information

Following our acquisitions of HIE and Texadian, we have three business segments: (i) Refining, Distribution and Marketing, (ii) Natural Gas and Oil Operations and (iii) Commodity Marketing and Logistics. Corporate and Other includes trust litigation and settlements and other administrative costs. Summarized financial information concerning reportable segments consists of the following (in thousands):

For the year ended December 31, 2013	Refining, Distribution and Marketing		Natural Gas and Oil Operations		Commodity Marketing and Logistics		Corporate and Other		Total
Sales and operating revenues	$	778,126	$	7,739	$	100,149	$	—	$	886,014
Depreciation, depletion, amortization     and accretion		2,267		1,686		2,009		20		5,982
Operating income (loss)		(19,318)		246		9,126		(29,367)		(39,313)
Loss from unconsolidated affiliate										(2,941)
Interest expense and financing costs, net										(19,471)
Other income (expense)										808
Change in value of common stock warrants										(10,114)
Gain on derivative instruments										410
Loss before income taxes										(70,621)
Income tax benefit										—
Net loss									$	(70,621)
Capital expenditures, including acquisitions	$	567,332	$	471	$	(1,300)	$	544	$	567,047

Following our acquisition of Texadian, at December 31, 2012, we had two business segments: (i) Natural Gas and Oil Operations and (ii) Commodity Marketing and Logistics. For the period from September 1 through December 31, 2012, all of the operations as reported on our consolidated statement of operations related to Natural Gas and Oil Operations. For the period from September 1 through December 31, 2012, expenditures for long term assets, including goodwill and other intangible assets by segment were as follows (in thousands):

	Natural Gas and Oil Operations		Commodity Marketing and Logistics		Corporate and Other		Total
Capital expenditures, including acquisitions	$	415	$	17,439	$	—	$	17,854

Total assets by segment were as follows (in thousands):

	Refining, Distribution  and Marketing		Natural Gas  and Oil  Operations		Commodity  Marketing and Logistics		Corporate and Other		Total
At December 31, 2013	$	655,712	$	109,316	$	52,048	$	10,009	$	827,085
At December 31, 2012	$	—	$	116,034	$	62,754	$	10,794	$	189,582

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Debt (Details 2)	12 Months Ended
	Dec. 31, 2013
2013 Fiscal Year [Member]
Debt Instrument [Line Items]
Debt Instrument, Maximum Leverage Ratio	5.75
2014 Fiscal Year [Member]
Debt Instrument [Line Items]
Debt Instrument, Maximum Leverage Ratio	5.50
2015 Fiscal Year [Member]
Debt Instrument [Line Items]
Debt Instrument, Maximum Leverage Ratio	5.25
2016 Fiscal Year [Member]
Debt Instrument [Line Items]
Debt Instrument, Maximum Leverage Ratio	5.00
2017 Fiscal Year, and at all times thereafter [Member]
Debt Instrument [Line Items]
Debt Instrument, Maximum Leverage Ratio	4.75

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Information Regarding Proved Oil and Gas Reserves (Details)	4 Months Ended		8 Months Ended		12 Months Ended
	Dec. 31, 2012 MMcf		Aug. 31, 2012 MMcf		Dec. 31, 2013 MMcf
Reserve Quantities [Line Items]
Ending Balance					236,587	[1]
Proved developed reserve	65,492	[1]			57,907	[1]
Proved undeveloped reserve	102,371	[1]			178,680	[1]
Natural Gas [Member]
Reserve Quantities [Line Items]
Ending Balance					187,259
Proved developed reserve	48,838				45,734
Proved undeveloped reserve	74,258				141,525
Oil [Member]
Reserve Quantities [Line Items]
Ending Balance					820
Proved developed reserve	523				401
Proved undeveloped reserve	594				419
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Ending Balance					7,401
Proved developed reserve	2,253				1,627
Proved undeveloped reserve	4,092				5,774
Company [Member]
Reserve Quantities [Line Items]
Beginning Balance	1,659	[1]			2,163	[1]
Revisions of quantity estimate	643	[1]			557	[1]
Extensions and discoveries					25	[1]
Production	(139)	[1]			(667)	[1]
Ending Balance	2,163	[1]			2,078	[1]
Proved developed reserve	1,875	[1]			2,078	[1]
Proved undeveloped reserve	288	[1]			0	[1]
Company [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning Balance	0				446
Revisions of quantity estimate	456				460
Extensions and discoveries					9
Production	(10)				(253)
Ending Balance	446		0		662
Proved developed reserve	158				662
Proved undeveloped reserve	288				0
Base Pricing, before adjustments for contractual differentials	2.56	[2]	2.75	[2]
Company [Member] | Oil [Member]
Reserve Quantities [Line Items]
Beginning Balance	277				286
Revisions of quantity estimate	31				16
Extensions and discoveries					3
Production	(22)				(69)
Ending Balance	286		277		236
Proved developed reserve	286				236
Proved undeveloped reserve	0				0
Base Pricing, before adjustments for contractual differentials	91.21	[2]	90.85	[2]	96.91	[2]
Company [Member] | Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning Balance	0				0
Revisions of quantity estimate	0				0
Extensions and discoveries					0
Production	0				0
Ending Balance	0				0
Proved developed reserve	0				0
Proved undeveloped reserve	0				0
Base Pricing, before adjustments for contractual differentials					3.53	[2]
Company's Share of Piceance Energy [Member]
Reserve Quantities [Line Items]
Beginning Balance	0	[1]			165,700	[1]
Transfer from investees	112,639	[1],[3]
Revisions of quantity estimate	10,621	[1]			90,387	[1]
Extensions and discoveries	44,151	[1]			(6,643)	[1]
Production	(1,711)	[1]			(14,935)	[1]
Ending Balance	165,700	[1]			234,509	[1]
Proved developed reserve	63,617	[1]			55,829	[1]
Proved undeveloped reserve	102,083	[1]			178,680	[1]
Company's Share of Piceance Energy [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning Balance	0				122,650
Transfer from investees	83,915	[3]
Revisions of quantity estimate	8,053				72,436
Extensions and discoveries	32,073				3,599
Production	(1,391)				(12,088)
Ending Balance	122,650				186,597
Proved developed reserve	48,680				45,072
Proved undeveloped reserve	73,970				141,525
Base Pricing, before adjustments for contractual differentials	2.56	[2]
Company's Share of Piceance Energy [Member] | Oil [Member]
Reserve Quantities [Line Items]
Beginning Balance	0				831
Transfer from investees	560	[3]
Revisions of quantity estimate	41				174
Extensions and discoveries	236				(374)
Production	(6)				(47)
Ending Balance	831				584
Proved developed reserve	237				165
Proved undeveloped reserve	594				419
Base Pricing, before adjustments for contractual differentials	91.21	[2]			96.91	[2]
Company's Share of Piceance Energy [Member] | Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning Balance	0				6,345
Transfer from investees	4,228	[3]
Revisions of quantity estimate	387				2,818
Extensions and discoveries	1,778				(1,334)
Production	(48)				(428)
Ending Balance	6,345				7,401
Proved developed reserve	2,253				1,627
Proved undeveloped reserve	4,092				5,774
Base Pricing, before adjustments for contractual differentials					3.53	[2]
Predecessor [Member] | Company [Member]
Reserve Quantities [Line Items]
Beginning Balance			90,173	[1],[4]
Revisions of quantity estimate			512	[1]
Sale/disposition of properties			(83,770)	[1],[5]
Production			(5,256)	[1]
Predecessor [Member] | Company [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning Balance			87,209	[4]
Revisions of quantity estimate			0
Sale/disposition of properties			(82,357)
Production			(4,852)
Predecessor [Member] | Company [Member] | Oil [Member]
Reserve Quantities [Line Items]
Beginning Balance			494	[4]
Revisions of quantity estimate			85
Sale/disposition of properties			(235)	[5]
Production			(67)
Predecessor [Member] | Company [Member] | Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning Balance			0	[4]
Revisions of quantity estimate			0
Sale/disposition of properties			0	[5]
Production			0

[1] MMcfe is based on a ratio of 6 Mcf to 1 barrel.

[2] 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.

[3] On August 31, 2012, certain reserves held by Delta Petroleum and by Laramie were transferred to Piceance Energy in exchange for a 33.34% and a 66.66% equity ownership interest, respectively (See Note 3 - Investment in Piceance Energy)

[4] At January 1, 2012, gas is based on 70,982 MMcf of natural gas and 4,057 MBbl of natural gas liquids, with liquids converted to gas using a ratio of 4 Mcf to 1 barrel.

[5] On August 31, 2012, substantially all of the reserves of the Company were transferred to Piceance Energy in exchange for a 33.34% equity ownership interest (See Note 4).

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended	8 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Aug. 31, 2012 Predecessor [Member]
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (8,839)	$ (70,621)	$ (45,437)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion	401	5,982	16,041
Non cash interest expense	1,056	16,742	2,989
Change in asset values due to fresh - start accounting adjustments	0	0	14,765
Gain on extinguishment of senior debt	0	0	(166,144)
Gain on settlement of liabilities	0	0	(2,188)
(Gain) loss on property sales	(82)	(50)	126
Dry hole costs and impairments	0	0	151,347
Stock-based compensation	34	1,161	1,895
Change in value of common stock warrants	4,280	10,114	0
Loss from unconsolidated affiliates	1,325	2,941	20
Deferred income tax expense (benefit)	(2,757)	179	0
Other	0	0	(699)
Net changes in operating assets and liabilities:
Trade accounts receivable	(2,234)	(45,698)	3,472
Prepaids and other current assets	(538)	(2,569)	(1,378)
Inventories	0	40,141	0
Accounts payable	2,718	15,829	(4,187)
Supply and exchange agreements	0	(13,061)	0
Settlement liability	0	1,898	0
Accrued reorganization costs	0	0	9,116
Other accrued liabilities	0	1,335	0
Net cash used in operating activities	(4,636)	(35,677)	(20,262)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	0	(7,768)	(1,613)
Acquisitions, net of cash acquired	(17,439)	(559,279)	0
Proceeds from asset sales	0	2,850	74,209
Proceeds from sale of other fixed assets	39	0	26
Capitalized drilling costs paid to operator	(415)	(303)	0
Proceeds from sale of unconsolidated affiliates	125	0	0
Net cash (used in) provided by investing activities	(17,690)	(564,500)	72,622
CASH FLOWS FROM FINANCING ACTIVITIES:
Funding of purchase of HIE from supply and exchange agreements	0	378,238	0
Proceeds from sale of common stock, net of offering costs	0	199,170	0
Proceeds from exercise of common stock warrants	0	18	0
Proceeds from borrowings	35,000	159,800	23,000
Repayments of borrowings	0	(121,909)	(59,535)
Payment of deferred loan costs	0	(2,264)	0
Fund distribution agent account	0	0	(21,805)
Proceeds from (funding of) Wapiti and General Recovery Trusts	2,446	0	(2,000)
Recoveries from bankruptcy settlements	5,183	0	0
Restricted cash released from (held to) secure letter of credits	(19,000)	19,000	0
Net cash provided by (used in) financing activities	23,629	632,053	(60,340)
Net increase (decrease) in cash and cash equivalents	1,303	31,876	(7,980)
Cash at beginning of period	4,882	6,185	12,862
Cash at end of period	6,185	38,061	4,882
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest and financing costs	0	2,186	3,745
NON-CASH INVESTING AND FINANCING ACTIVITIES
Stock issued used to settle bankruptcy claims	0	2,605	0
Interest payable capitalized to principal balance	0	6,096	0
Non-cash additions to property, plant and equipment	$ 209	$ 0	$ 0

XML

CONSOLIDATED BALANCE SHEETS [Parenthetical] (USD $)	Dec. 31, 2013	Dec. 31, 2012
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	3,000,000	3,000,000
Preferred stock, shares issued	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	300,000,000
Common stock, shares issued	30,151,000	15,008,092

XML

Debt

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

Note 10 - Debt

Our debt is as follows (in thousands):

	December 31,
	2013		2012
Tranche B Loan	$	19,480	$	35,000
Delayed Draw Term Loan Agreement		—		13,465
ABL Facility		51,800		—
Retail Credit Agreement		26,000		—
Less: unamortized debt discount – warrants		—		(6,014)
Less: unamortized debt discount – embedded derivative		—		(60)
Total debt, net of unamortized debt discount		97,280		42,391
Less: current maturities		(3,250)		(35,000)
Long-term debt, net of current maturities and unamortized discount	$	94,030	$	7,391

Annual maturities of our long-term debt are due during the following years (in thousands):

Year		Amount Due
2014	$	3,250
2015		2,600
2016		22,080
2017		54,400
2018		2,600
Thereafter		12,350
	$	97,280

Delayed Draw Term Loan Credit Agreement

Pursuant to the Plan, on the Emergence Date, we and certain of our subsidiaries (the “Guarantors” and, together with the company, the “Loan Parties”) entered into a Delayed Draw Term Loan Credit Agreement (the “Loan Agreement”) with Jefferies Finance LLC, as administrative agent (the “Agent”) for the lenders party thereto from time to time, including WB Delta, Ltd., Waterstone Offshore ER Fund, Ltd., Prime Capital Master SPC, GOT WAT MAC Segregated Portfolio, Waterstone Market Neutral MAC51, Ltd., Waterstone Market Neutral Master Fund, Ltd., Waterstone MF Fund, Ltd., Nomura Waterstone Market Neutral Fund, ZCOF Par Petroleum Holdings, L.L.C. and Highbridge International, LLC (collectively, the “Lenders”), pursuant to which the Lenders agreed to extend credit to us in the form of term loans (each, a “Loan” and collectively, the “Loans”) of up to $30 million. We borrowed $13 million on the Emergence Date in order to, along with the proceeds from the Contribution Agreement: (i) repay the loans and obligations due under the Predecessor’s secured debtor-in-possession credit facility, and (ii) pay allowed but unpaid administrative expenses to the Debtors related to the Plan. During 2013, we borrowed an additional $17 million for general corporate use.  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. Included in interest expense and financing cost, net on the consolidated statements of operations is $6.1 million recorded as loss on extinguishment of debt related to the November 2013 repayment.

Amendment to the Loan Agreement

On December 28, 2012, in order to fund a portion of the purchase price for our acquisition of Texadian Energy, the Loan Parties entered into an amendment to the Loan Agreement with the Agent and the Lenders, pursuant to which certain lenders (the “Tranche B Lenders”) agreed to extend additional borrowings to us (the “Tranche B Loan”). The total commitment of the Tranche B Loan of $35 million was drawn at closing. In addition to funding a portion of the purchase price of the acquisition of Texadian, the Tranche B Loan provided cash collateral for our former cash collateralized letter of credit facility. Pursuant to the Eighth Amendment to the Loan Agreement entered into on June 24, 2013, the Lenders refinanced and replaced the Tranche B Loan with new Tranche B Loans in the aggregate principal amount of $65 million (the “New Tranche B Loans”). The proceeds from the New Tranche B Loans were applied to prepay in full the Tranche B Loan, to make payments due under the membership interests purchase agreement in connection with the acquisition of HIE (the “HIE Purchase Agreement”), and for working capital and general corporate purposes.

On September 25, 2013 and in connection with the acquisition of HIE, we entered into a Tenth Amendment to the Loan Agreement pursuant to which the Lenders (i) consented to the consummation of the transactions contemplated by the HIE Purchase Agreement and the use of a portion of the proceeds from the Private Placement to fund a portion of the consideration for the acquisition of HIE and for certain other purposes, (ii) provided certain other consents in connection with the transactions contemplated by the HIE Purchase Agreement, (iii) increased the interest rate applicable to certain of the loans, and (iv) amended certain provisions of the Loan Agreement and the other loan documents in connection with the consummation of the transactions contemplated by the HIE Purchase Agreement and the Private Placement (see Note 14 – Stockholder’s Equity).  

The consent provided by the Lenders was conditioned on, among other things, (i) the repayment in full of the New Tranche B Loans owing to all Lenders except for ZCOF Par Petroleum Holdings, L.L.C., and a partial repayment of the New Tranche B Loans owing to ZCOF Par Petroleum Holdings, L.L.C. from a portion of the proceeds from the Private Placement and (ii) a portion of the proceeds from the Private Placement being used to consummate the transactions contemplated by the HIE Purchase Agreement.  

The New Tranche B Loans bear interest (a) from June 24, 2013 through October 31, 2013 at a rate equal  to 9.75% per annum payable, at the election of the company, either (i) in cash or (ii) in kind, and (b) from and after November 1, 2013, at a rate equal to 14.75% per annum payable either (i) in cash or (ii) in kind. Additionally, we agreed to pay the New Tranche B Lenders a nonrefundable exit fee equal to 2.5% of the aggregate amount of the New Tranche B Loans. The exit fee is earned in full and payable on the maturity date of the Tranche B Loans or, if earlier, the date on which the New Tranche B Loans are paid in full.  

The New Tranche B Loans mature and are payable in full on August 31, 2016. We may prepay the New Tranche B Loans at any time, provided that any prepayment is in an integral multiple of $100,000 and not less than $100,000 or, if less, the outstanding principal amount of the New Tranche B Loans. Amounts to be applied to prepayment of New Tranche B Loans shall be applied (i) first, towards payment of interest then outstanding and fees then due, and (ii) second, towards payment of principal then outstanding.

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.

ABL Facility

On September 25, 2013 and in connection with the with the acquisition of HIE, HIE and its subsidiary (the “ABL Borrowers”) and Hawaii Pacific Energy entered into an asset-based revolving credit facility (the “ABL Facility”) to provide the ABL Borrowers with a senior secured revolving credit facility of up to $125.0 million under which the ABL Borrowers may borrow amounts from time to time based on the available borrowing base as determined in accordance with the ABL Facility. The ABL Facility also allows the ABL Borrowers to use up to $50 million of availability under the ABL Facility for the issuances of letters of credit. The ABL Borrowers borrowed $15 million on September 25, 2013 under the ABL Facility in order to, in part, (i) fund the purchase price under the Purchase Agreement, and (ii) provide working capital to the ABL Borrowers. The proceeds from any future amounts borrowed pursuant to the ABL Facility will be used for general corporate purposes and to fund the working capital of the ABL Borrowers. As of December 31, 2013, the total capacity of the ABL Facility was $83.3 million.

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 LIBO rate specified below (“LIBO Rate”) 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 LIBO Rate 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 LIBO Rate for a LIBO Rate loan denominated in dollars with a one-month interest period commencing on such day plus 1.00%. The effective weighted-average interest rate for 2013 was 3.13%. 

The amounts borrowed pursuant the ABL Facility and all obligations arising under the ABL Facility are secured by a lien in favor of the ABL Agent on substantially all of HIE’s assets.

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 LIBO Rate 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 Facility requires HIE and its subsidiaries and Hawaii Pacific Energy to comply with various affirmative and negative covenants affecting its business and operations, including compliance by HIE in certain circumstances with a minimum ratio of consolidated earnings before interest, taxes, depreciation and amortization (“EBITDA”), as adjusted, to total fixed charges of 1.0 to 1.0.

HIE Retail Credit Agreement

On  November 14, 2013 , HIE Retail, LLC (“HIE Retail”), our subsidiary, entered into a Credit Agreement (the “Retail Credit Agreement”) in the form of a senior secured term loan of up to $30 million  the (“Term Loan”) and a senior secured revolving line of credit of up to $5 million (the “Revolver”). HIE Retail initially borrowed $26 million of the Term Loan at the closing and an additional $4 million of the Term Loan upon HIE Retail’s compliance with certain liquor licensing requirements, if such requirements are satisfied prior to December 31, 2014, will be available. The proceeds of the Term Loan are available for general corporate purposes.

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) as follows:

Period (during and as of the last day of)	Maximum Leverage Ratio
2013 Fiscal Year	5.75 to 1.00
2014 Fiscal Year	5.50 to 1.00
2015 Fiscal Year	5.25 to 1.00
2016 Fiscal Year	5.00 to 1.00
2017 Fiscal Year, and at all times thereafter	4.75 to 1.00

HIE Retail is also required to maintain a Fixed Charge Coverage Ratio of 1.15:1.00.

Term Loan

Principal on the Term Loan will be repaid in 28 quarterly principal payments over the term through November 14, 2020.

The Term Loan will bear 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. The effective interest rate for 2013 on the outstanding loan was 2.5%.

Interest is payable at the end of the selected interest period, but no less frequently than quarterly.  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	%	0	%
2	4.00x-5.00x	2.25	%	.25	%
3	>5.00x	2.5	%	.50	%

Initial pricing from the Effective Date until March 31, 2014 was set at Level 2.

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.

Revolver

T he Revolver matures on November 14, 2016. Letters of credit issued under the Revolver are not to expire beyond the maturity date of the Revolver.

Advances under the 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 (the “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 commencing on the November 14, 2013.

The 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	.25	%	1.75	%	-.25	%
2	4.00x-5.00x	.375	%	2.00	%	0	%
3	>5.00x	.50	%	2.25	%	.25	%

Initial pricing from the Effective Date until March 31, 2014 was set at Level 2.

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. Fees for the issuance and negotiation of Commercial Letters of Credit will be based on the Agent’s standard fee schedule then in effect.

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, 2013, we had $41.6 million of letters of credit outstanding related to this agreement.

Letter of Credit Facility

 On December 27, 2012, we entered into a letter of credit facility agreement (the “Letter of Credit Facility”). The Letter of Credit Facility provided for a letter of credit facility in an aggregate principal amount of $30 million that was available for the issuance of cash-collateralized standby letters of credit for us or any of our subsidiaries.

 In connection with the acquisition of Texadian, we issued an Irrevocable Standby Letter of Credit in favor of SEACOR Holdings, Inc. in the amount of $11.7 million (the “Irrevocable Standby Letter of Credit”). The Irrevocable Standby Letter of Credit secured SEACOR Holdings, Inc. in the event that certain letters of credit were drawn. Those letters of credit have been terminated and released. The Letter of Credit Facility was terminated on June 17, 2013.

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, 2013, we are in compliance with all of our credit agreements.  

Warrant Issuance Agreement

Pursuant to the Plan of Reorganization, on the Emergence Date, we issued to the Lenders warrants (the “Warrants”) to purchase up to an aggregate of 959,213 shares of our common stock (the “Warrant Shares”). In connection with the issuance of the Warrants, we also entered into a Warrant Issuance Agreement, dated as of the Emergence Date (the “Warrant Issuance Agreement”). Subject to the terms of the Warrant Issuance Agreement, the holders are entitled to purchase shares of common stock upon exercise of the Warrants at an exercise price of $0.10 per share of common stock (the “Exercise Price”), subject to certain adjustments from time to time as provided in the Warrant Issuance Agreement. The Warrants expire on the earlier of (i) August 31, 2022 or (ii) the occurrence of certain merger or consolidation transactions specified in the Warrant Issuance Agreement. A holder may exercise the Warrants by paying the applicable exercise price in cash or on a cashless basis.

The number of shares of our common stock issuable upon exercise of the Warrants and the exercise prices of the Warrants will be adjusted in connection with certain issuances or sales of shares of the company’s common stock and convertible securities, or any subdivision, reclassification or combinations of common stock. Additionally, in the case of any reclassification or capital reorganization of the capital stock of the company, the holder of each Warrant outstanding immediately prior to the occurrence of such reclassification or reorganization shall have the right to receive upon exercise of the applicable Warrant, the kind and amount of stock, other securities, cash or other property that such holder would have received if such Warrant had been exercised.

From the Emergence Date through December 31, 2013, we issued an additional 228,735 shares of our common stock to settle bankruptcy matters. This entitled the Lenders to receive an additional 14,859 Warrant Shares through December 31, 2013. On December 12, 2013, Warrants to purchase 183,389 Warrant Shares were exercised. At December 31, 2013, Warrants to purchase an aggregate of  790,683 Warrant Shares were outstanding.

Based on certain anti-dilution provisions in the Warrant Issuance Agreement, we have concluded that the Warrants are not indexed to our equity. Accordingly, on the Emergence Date we estimated the fair value of the Warrants on the date of grant to be approximately $6.6 million and recorded the estimated fair value of the Warrants as a derivative liability with the offset to debt discount. The debt discount was being amortized over the life of the Loan Agreement, using the effective interest method until repayment of the delayed draw term loan in November 2013. Subsequent changes in the fair value of the Warrants are reflected in earnings (see Note 11 – Fair Value Measurements ).  

XML

Subsequent Events (Details Textual) (USD $)			1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Jan. 23, 2014 Subsequent Event [Member]
Subsequent Event [Line Items]
Common Stock Shares Authorized	500,000,000	300,000,000
Common stock, shares issued	30,151,000	15,008,092	301,141,520
Common Stock Par Or Stated Value Per Share	$ 0.01	$ 0.01
Stockholders Equity, Reverse Stock Split			1:10 reverse stock split

XML

Income Taxes (Details 2) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred tax assets:
Net operating loss	$ 540,867	$ 450,195
Capital loss carry forwards	26,141	26,141
Property and equipment	34,683	23,045
Investment in Piceance Energy	32,138	45,172
Derivative instruments	0	1,498
Accrued bonuses	0	0
Trust liabilitiy	1,327	0
Other	1,183	1,506
Total deferred tax assets	636,339	547,557
Valuation allowance	(633,954)	(544,442)
Net deferred tax assets	2,385	3,115
Deferred tax liabilities:
Property and equipment	5	0
Texadian Energy intangibles	2,380	3,083
Prepaid insurance, marketable securities and other	0	32
State liabilities	216	0
Total deferred tax liabilities	2,601	3,115
Total deferred tax liability, net	$ (216)	$ 0

XML

Income Taxes (Details) (USD $) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Aug. 31, 2012 Predecessor [Member]	Dec. 31, 2012 Predecessor [Member]
Current:
U.S.—Federal	$ 0	$ 0	$ 0
U.S.—State	0	(179)	0
Deferred:
U.S.—Federal	(2,757)	(14)	0
U.S.—State	0	193	0
Total	$ (2,757)	$ 0	$ 0	$ 154,000

XML

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 26, 2014	Jun. 28, 2013
Document Information [Line Items]
Entity Registrant Name	PAR PETROLEUM CORP/CO
Entity Central Index Key	0000821483
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Trading Symbol	PARR
Entity Common Stock, Shares Outstanding		30,159,039
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 55,000,000

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

Note 11 - 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 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 the valuation techniques discussed below 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.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Fresh-Start Reporting –  The fair value of the Successor was based on its estimated enterprise value post-bankruptcy using valuation techniques described in notes (a) through (e) below. The individual components consist of the estimated enterprise value of Piceance Energy and the sum of the estimated fair value of the assets we retained. The estimates of fair value of the net assets were reflected in the Successor’s consolidated balance sheet as of August 31, 2012.

	Fair Value at		Fair Value
	August 31, 2012		Technique
	(in thousands)
Oil and gas properties
Proved	$	4,587	(a)(b)
Other assets
Frac tanks		1,400	(c)
Compressors		2,800	(c)
Miscellaneous		39	(d)
Investment in Piceance Energy		105,344	(e)

(a) Certain proved property was valued using the cost valuation technique. A significant input in this measurement was the estimated cost of the properties. A change in that estimated cost would be directly correlated to change in the estimated fair value of the property. We consider this to be a Level 3 fair value measurement.

(b) The estimated fair value of our Point Arguello Unit offshore California was valued using a market valuation technique based on standalone bids received by third-parties during the sale process. We consider this to be a Level 2 fair value measurement.

(c) The estimated fair value of our frac tanks and compressor units was valued using a market valuation technique which was based on published listings of similar equipment or standalone bids received by third-parties. We consider these to be Level 2 fair value measurements.

(d) Miscellaneous assets (assets that we were unable to value using the income or market valuation techniques) were valued using the cost valuation technique. We consider this to be a Level 3 fair value measurement.

(e) The estimated fair value of our investment in Piceance Energy was based on its enterprise value and uses various valuation techniques including (i) an income approach based on proved developed reserves’ future net income discounted back to net present value based on the weighted average cost of capital for comparable independent oil and natural gas producers, and (ii) a market multiple approach. Proved property was valued using the income approach. A discounted cash flow model was prepared based off of an independent reserve report with a discount rate of 10% applied to proved developed producing reserves, 15% to proved developed non-producing reserves and 20% to proved undeveloped reserves. The prices for oil and natural gas were forecasted based on NYMEX strip pricing adjusted for basis differentials. For the market multiple approach, we reviewed the transaction values of recent similar asset transactions and compared the purchase price per Mcfe of proved developed reserves and purchase price per Mcfe per day of net equivalent production of those transactions to the independent reserve report. Unproved acreage was valued using a cost approach based on recent sales of acreage in the area. Based on these valuations, the equity value of our 33.34% interest in Piceance Energy was estimated to be approximately $105.3 million on the Emergence date. We consider this to be a Level 3 fair value measurement.

Purchase Price Allocation of Texadian – The fair values of the assets acquired and liabilities assumed as a result of the Texadian acquisition were estimated as of the date of the acquisition using valuation techniques described in notes (a) through (f) described below.

	Fair Value at		Fair Value
	December 31, 2012		Technique
	(in thousands)
Net non-cash working capital	$	3,631	(a)
Supplier relationship		3,360	(b)
Historical shipper status		2,200	(c)
Railcar leases		3,249	(d)
Goodwill		7,756	(e)
Deferred tax liabilities		(2,757)	(f)
	$	17,439

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

(b) The estimated fair value of the supplier relationship was estimated using a form of the income approach, the Multiple-Period Excess Earnings Method. Significant inputs used in this model include estimated cash flows from the suppliers, customer growth and rates and a discount rate. An increase in the cash flows attributable to the supplier relationships would result in an increase in the value of such relationship, while an increase in the discount rate would result in a decrease in the value. We consider this to be a Level 3 fair value measurement.

(c) The estimated fair value of the historical shipper status was estimated using a form of the income approach, the Greenfield Method. Significant inputs used in this model include estimated cash flows with and without the historical shipper status, and a discount rate. An increase in the cash flows attributable to the shipper would result in an increase in the value of such relationship, while an increase in the discount rate would result in a decrease in the value. We consider this to be a Level 3 fair value measurement.

(d) The estimated fair value of the railcar leases was estimated using a form of the income approach, the Lost Income Method. Significant inputs used in this model include the cost of providing services with and without the favorable railcar leases and a discount rate. An increase in market rates of railcar leases would result in an increase in the value attributable to the acquired leases. We consider this to be a Level 3 fair value measurement.

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

(f) A deferred tax liability has been recorded since the acquired intangible assets will not be deductible for tax purposes until the eventual sale of the company.

Purchase Price Allocation of HIE – The preliminary 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 using valuation techniques described in notes (a) through (g) described below.

	Fair Value at		Fair Value
	September 25, 2013		Technique
	(in thousands)
Net working capital	$	462,059	(a)
Property, plant and equipment		58,782	(b)
Land		39,800	(c)
Trade names and trade marks		4,689	(d)
Goodwill		13,613	(e)
Contingent consideration liability		(11,980)	(f)
Other noncurrent liabilities		(6,384)	(g)
	$	560,579

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

(b) The estimated 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 estimated 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 estimated 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.

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

(f) The estimated 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 noncurrent assets and liabilities are recorded at their estimated net present value as estimated by management.

Assets and Liabilities Measure at Fair Value on a Recurring Basis

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

	December 31,
	2013			2012
Stock price	$	22.30		$	12.00
Initial exercise price	$	0.1		$	0.1
Term (years)		8.67			9.67
Risk-free rate		2.78	%		1.68	%
Expected volatility		52.9	%		75.0	%

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 Warrants was $21.64 and $11.30 per share, or approximately $17.3 million and $10.9 million, as of December 31, 2013 and 2012, respectively. Since the 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 Warrants other than changes in the value of our common stock. Increases in the value of our common stock will directly be correlated to increases in the value of the Warrants. Likewise, a decrease in the value of our common stock will result in a decrease in the value of the Warrants.

Debt Prepayment Derivative - Our Loan Agreement contained mandatory repayments subject to premiums as set forth in the agreement. Factors such as the sale of assets, distributions from our investment in Piceance Energy, issuance of additional debt or issuance of additional equity may result in a mandatory prepayment. We considered the contingent prepayment feature to be an embedded derivative which was bifurcated from the loan and accounted for as a derivative. The fair value of the embedded derivative was estimated using an income valuation technique and a Crystal Ball forecast. The fair value measurement is considered to be a Level 3 fair value measurement. We do not believe that changes to the inputs in the model would have a significant impact on the valuation of the embedded derivative, other than a change to the estimate of the probability that a triggering event would occur. An increase in the probability of a triggering event occurring would cause an increase in the fair value of the embedded derivative. Likewise, a decrease in the probability of a triggering event occurring would cause a decrease in the value of the embedded derivative. At December 31, 2012, we estimated the fair value of the embedded derivative to be $145 thousand based on the probability of us repaying the loan prior to maturity. In November 2013, we repaid in full and terminated all of our obligations, including any repayment premiums, under this Loan Agreement (other than the new Tranche B loans described above) extinguishing the liability (see Note 10 - Debt).

Derivative instruments – With the acquisition of Texadian, we assumed certain open positions consisting of non-exchange traded fixed price physical contracts. These contracts were not treated as normal purchase or normal sales contracts and changes in fair value were recorded in earnings. In addition, we had certain exchange traded oil contracts that settled during the period and had no open positions as of December 31, 2013.  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. As of December 31, 2013, we had no open positions relating to these non-exchange traded fixed price physical contracts for which we have not elected the  normal purchase or normal sale exception.

Contingent consideration liability – As described in Note 4, the purchase price for our acquisition of HIE may be increased pursuant to an earn out provision. The initial value of the contingent consideration was estimated to be approximately $12.0 million. The liability is re-measured at the end of each reporting period using the valuation technique as described above. We do not believe that there has been a material change in the liability from September 25, 2013 through December 31, 2013.

Financial Statement Impact

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012 and their placement with our consolidated balance sheet consist of the following (in thousands):

	Location on
	Consolidated		Fair Value at	Fair Value at
	Balance Sheet	December 31, 2013		December 31, 2012
Commodities – physical forward     contracts	Prepaid and other current assets	$	—	$	(307)
Commodities – exchange traded     futures	Prepaid and other current assets		—		542
Warrant derivatives	Derivative liabilities		(17,336)		(10,900)
Contingent consideration liability	Contingent consideration liability		(11,980)		—
Debt repayment derivative	Derivative liabilities		—		(45)

The following table summarizes the pre-tax effect resulting from changes in fair value of derivative instruments charged directly to earnings (in thousands):

				September 1
				through
		December 31, 2013		December 31, 2012
		Gain (loss)		Gain (loss)
	Income Statement	recognized in		recognized in
	Classification	income		income
Derivatives not designated as     hedges:
Warrants	Change in value of warrants	$	(10,114)	$	(4,280)
Debt repayment derivative	Interest expense and financing costs, net		45		—
Commodities - exchange traded     futures	Gain on derivative instruments, net		104		—
Commodities - physical forward     contracts	Gain on derivative instruments, net		306		—

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012 and their level within the fair value hierarchy is as follows (in thousands):

	December 31, 2013
	Fair Value		Level 1		Level 2		Level 3
Liabilities
Warrants derivative	$	(17,336)	$	—	$	—	$	(17,336)
Contingent consideration liability		(11,980)		—		—		(11,980)
	$	(29,316)	$	—	$	—	$	(29,316)

	December 31, 2012
	Fair Value		Level 1		Level 2		Level 3
Assets
Commodities – exchange traded futures	$	542	$	542	$	—	$	—
Liabilities
Warrants derivative	$	(10,900)	$	—	$	—	$	(10,900)
Debt prepayment derivative		(45)		—		—		(45)
Commodities – physical forward contracts		(307)		—		(307)		—
	$	(11,252)	$	—	$	(307)	$	(10,945)

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

Description	2013		2012
Balance, at beginning of period	$	(10,945)	$	(6,665)
Settlements		3,723		—
Acquired		(11,980)		—
Total unrealized losses included in earnings		(10,114)		(4,280)
Transfers		—		—
Balance, at end of period	$	(29,316)	$	(10,945)

The carrying value and fair value of long-term debt and other financial instruments as of December 31, 2013 and 2012 is as follows (in thousands):

	December 31, 2013
	Carrying Value		Fair Value(1)
Tranche B	$	19,480	$	18,800
ABL Facility		51,800		51,800
HIE Retail Credit Agreement		26,000		26,000
Warrants		17,336		17,336
Contingent consideration liability		11,980		11,980

	December 31, 2012
	Carrying Value		Fair Value(1)
Long-term debt	$	7,391	$	10,900
Warrants		10,900		10,900
Debt repayment derivative		45		45

_________________________________________________________ 

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

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.

We estimate our long term debt’s fair value using a discounted cash flow analysis and an estimate of the current yield of 5.72% and 5.72% as of December 31, 2013 and 2012, respectively, by reference to market interest rates for term debt of comparable companies.

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Fair Value Measurements (Details 8) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, Carrying Value	$ 94,030		$ 7,391
Warrants, Carrying Value	17,336		10,945
Contingent consideration liability, Carrying Value	11,980
Debt repayment derivative, Carrying Value			45
Long-term Debt, Fair Value			10,900
Warrants, Fair Value	17,336	[1]	10,900
Contingent consideration liability, Fair Value	11,980	[1]
Debt repayment derivative, Fair Value			45
Tranche B [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Line of Credit, Noncurrent	19,480
Lines of Credit, Fair Value Disclosure	18,800
ABL Facility [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Line of Credit, Noncurrent	51,800		0
Lines of Credit, Fair Value Disclosure	51,800	[1]
HIE Retail Credit Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Line of Credit, Noncurrent	26,000
Lines of Credit, Fair Value Disclosure	$ 26,000	[1]

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

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Stockholders' Equity (Details Textual) (USD $)	4 Months Ended	12 Months Ended		1 Months Ended	12 Months Ended									12 Months Ended		12 Months Ended		1 Months Ended	12 Months Ended				12 Months Ended		8 Months Ended	1 Months Ended			12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 20, 2012	Jan. 23, 2014 Subsequent Event	Dec. 31, 2012 Board Of Directors [Member]	Dec. 31, 2013 Restricted Stock [Member]	Dec. 31, 2012 Restricted Stock [Member]	Dec. 31, 2013 Restricted Stock [Member] Board Of Directors [Member]	Dec. 31, 2013 Common Stock [Member]	Dec. 31, 2013 Common Stock [Member] Settlement of Bankruptcy Claims [Member]	Dec. 31, 2013 Common Stock [Member] Exercise of Warrants [Member]	Dec. 31, 2013 Common Stock [Member] Employees and Directors [Member]	Dec. 31, 2013 Maximum [Member]	Dec. 31, 2013 Maximum [Member] Employees and Directors [Member]	Dec. 31, 2012 Maximum [Member] Board Of Directors [Member]	Dec. 31, 2013 Minimum [Member] Employees and Directors [Member]	Dec. 31, 2012 Minimum [Member] Board Of Directors [Member]	Dec. 31, 2012 Incentive Plans [Member]	Dec. 31, 2012 Incentive Plans [Member]	Dec. 31, 2012 Incentive Plans [Member] Chairperson Of Audit Committee [Member]	Dec. 31, 2012 Incentive Plans [Member] Non Chairman Audit Committee [Member]	Dec. 31, 2013 Restatement [Member]	Dec. 31, 2013 Form S-1 [Member]	Dec. 31, 2013 Form S-3 [Member]	Aug. 31, 2012 Predecessor [Member]	Jun. 21, 2011 Predecessor [Member] Common Stock [Member]	Dec. 31, 2013 7% Senior Unsecured Notes, due 2015 [Member]	Dec. 31, 2013 3 3/4% Senior Convertible Notes, due 2037 [Member]	Dec. 31, 2013 Senior Unsecured Note [Member]	Dec. 31, 2013 Unsecured Debt [Member]
Class of Stock [Line Items]
Interest percentage of senior notes																											7.00%	3.75%
Maturity period																											2015	2037
Shares allotted to note holders																													14,573,608	191,973
Number of shares issuable under warrants		959,213											1,220,000
Number of shares authorized			1,600,000																			303,000,000
Common Stock Shares Authorized	300,000,000	500,000,000																				300,000,000
Preferred stock, shares authorized	3,000,000	3,000,000																				3,000,000
Preferred stock, par value	$ 0.01	$ 0.01																				$ 0.01
Expected Market Value Of Registrable Shares																							$ 15,000,000	$ 5,000,000
Stockholders Equity Reverse Stock Split				1:10 reverse stock split
Common shares Issued					3,000
Common shares Issued amount	34,000	1,164,000			33,000
Share price	$ 12.00	$ 22.30													$ 12.00		$ 10.00
Non-vested shares Granted						355,481	219,183																		0	489,227
Vesting period						5 years		1 year
Unrecognized compensation cost						8,100,000
Weighted average period						4 years 4 months 13 days
Annual retainer to amount																			50,000	15,000	5,000
Annual grant of restricted stock																		75,000	75,000
Period of volume weighted average share price																		60 days
Value of shares on the grant date, floor																										$ 5.50
Stock compensation expense																									1,900,000
Stock Issued During Period, Shares, New Issues									14,400,000	208,000	183,000	6,000
Proceeds from Issuance of Common Stock	0	199,170,000							200,000,000																0
Share Based Compensation	34,000	1,161,000				1,200,000						90,000													1,895,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value														$ 19.87		$ 12.22
Stock Repurchase Program, Price of Common Stock		$ 13.90
Maximum Amount of Repurchase Rights Agreement		$ 50,000,000

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	4 Months Ended		12 Months Ended		8 Months Ended
	Dec. 31, 2012		Dec. 31, 2013		Aug. 31, 2012 Predecessor [Member]
Revenues
Refining, distribution and marketing revenues	$ 0		$ 778,126		$ 0
Commodity marketing and logistics revenues	0		100,149		0
Oil and gas sales	2,144		7,739		23,079
Total operating revenues	2,144		886,014		23,079
Operating expenses
Cost of revenues	0		848,924		0
Operating expense, excluding depreciation, depletion and amortization expense shown separately below	0		27,251		0
Lease operating expense	1,684		5,627		9,038
Transportation expense	0		0		6,963
Production taxes	4		49		979
Exploration expense	0		0		2
Dry hole costs and impairments	0		0		151,347
Depreciation, depletion and amortization	401		5,982		16,041
Trust litigation and settlements	0		6,206		0
General and administrative expense	4,520		21,494		9,386
Acquisition and integration costs	556		9,794		0
Total operating expenses	7,165		925,327		193,756
Operating loss	(5,021)		(39,313)		(170,677)
Other income and (expense):
Interest expense and financing costs, net	(1,056)		(19,471)		(6,852)
Other income	86		808		516
Change in value of common stock warrants	(4,280)		(10,114)		0
Gain on derivative instruments, net	0		410		0
Loss from unconsolidated affiliates	(1,325)		(2,941)		(20)
Total other expense	(6,575)		(31,308)		(6,356)
Loss before income taxes and reorganization items	(11,596)		(70,621)		(177,033)
Income tax benefit	(2,757)		0		0
Loss before reorganization items	(8,839)		(70,621)		(177,033)
Reorganization items
Professional fees and administrative costs	0		0		22,354
Changes in asset fair values due to fresh start accounting adjustments	0		0		14,765
Gain on settlement of senior debt	0		0		(166,144)
Gain on settlement of liabilities	0		0		(2,571)
Net loss	$ (8,839)		$ (70,621)		$ (45,437)
Basic loss per common share (in dollars per share)	$ (0.56)	[1]	$ (3.57)	[1]	$ (1.57)	[1]
Diluted loss per common share (in dollars per share)	$ (0.56)	[1]	$ (3.57)	[1]	$ (1.57)	[1]
Weighted average number of shares outstanding:
Basic (in shares)	15,734		19,740		28,841
Diluted (in shares)	15,734		19,740		28,841

[1] Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Therefore, we have utilized the basic weighted-average common shares outstanding to calculate both basic and diluted loss per share for all parties presented.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure [Text Block]

Note 5 – Property, Plant and Equipment

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

	December 31,
	2013		2012
Land	$	39,800	$	—
Buildings and equipment		65,878		—
Other		1,945		1,415
Property, plant and equipment		107,623		1,415
Proved oil and gas properties		4,949		4,804
Less: accumulated depreciation, depletion     and amortization		(3,968)		(373)
	$	108,604	$	5,846

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Acquisitions and Dispositions

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Business Combination Disclosure [Text Block]

Note 4 – Acquisitions and Dispositions

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.

Texadian Energy, Inc.

On December 31, 2012, we acquired Texadian, an indirect wholly-owned subsidiary of SEACOR Holdings Inc., for $14 million plus estimated net working capital of approximately $3 million at closing resulting in approximately $17 million of cash paid at closing. Texadian operates an oil transportation, distribution and marketing business with significant logistics capabilities. The purchase price for the acquisition was funded with a combination of cash and additional borrowings under the Tranche B Loan (see Note 10 - Debt). During 2013, the purchase price was reduced by $1.3 million due to funds received from SEACOR Holdings, Inc. for certain employee-related benefits.

The purchase was accounted for as a business combination whereby the purchase price is 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 Texadian’s, and specifically 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. These include relationships with suppliers and shippers and favorable railcar leases. These intangible assets will be amortized over their estimated useful lives on a straight line basis, which approximates their consumptive life.

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

Intangible assets	$	8,809
Goodwill		6,990
Net non cash-working capital		3,097
Deferred tax liabilities		(2,757)
Total, net of cash acquired	$	16,139

None of the goodwill or intangible assets are expected to be deductible for income tax reporting purposes.  Acquisition costs of approximately $556 thousand are included in our consolidated statements of operations for the period ended December 31, 2012.

HawaiiIndependent Energy, LLC

On June 17, 2013 (the “Execution Date”), our wholly-owned subsidiary, Hawaii Pacific Energy, entered into a membership interest purchase agreement (the “HIE Purchase Agreement”) with Tesoro Corporation, (the “Seller”) and solely for the purpose set forth in the HIE Purchase Agreement, Tesoro Hawaii. Pursuant to the HIE Purchase Agreement, on September 25, 2013 (the “Effective Date”), Hawaii Pacific Energy purchased from the Seller all of the issued and outstanding units representing the membership interests in Tesoro Hawaii (the “Purchased Units”), and indirectly thereby also acquired Tesoro Hawaii’s wholly-owned subsidiary, Smiley’s Super Service, Inc. Tesoro Hawaii owns and operates (i) a petroleum refinery located at the Campbell Industrial Park in Kapolei, Hawaii (the “Refinery”), (ii) certain pipeline assets, floating pipeline mooring equipment, and refined products terminals, and (iii) 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”).

Hawaii Pacific Energy acquired the Purchased Units for $75 million, paid in cash at the closing of the HIE Purchase Agreement, plus net working capital and inventories at closing and 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 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 in the event Hawaii Pacific Energy disposes of any facility used in the acquired business, Hawaii Pacific Energy's obligation to make earnout payments could be modified and/or accelerated as provided in the HIE Purchase Agreement. The purchase price was paid with a portion of the net proceeds from the sale of the shares of our common stock in a private transaction (see Note 14 - Stockholders’ Equity), amounts received pursuant to the Supply and Exchange Agreements (see Note 9 - Supply and Exchange Agreements) and the ABL Facility (see Note 10 - Debt).

We accounted for the acquisition of HIE as a business combination whereby the purchase price has been preliminary 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. These include 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.

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

Inventory	$	418,750
Trade accounts receivable		59,485
Prepaids and other current assets		1,978
Property, plant and equipment		58,782
Land		39,800
Goodwill		13,613
Intangible assets		4,689
Accounts payable and other current liabilities		(18,154)
Contingent consideration liability		(11,980)
Other noncurrent liabilities		(6,384)
Total	$	560,579

We are continuing to evaluate certain liabilities assumed in the acquisition, including those related to employee benefits. We have recorded a preliminary estimate of the liability and expect to finalize the purchase price allocation during 2014.

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

Pro Forma Effects of the Acquisitions

The unaudited pro forma financial information presented below assumes that the Texadian and HIE acquisitions occurred as of January 1, 2012 and combines the Predecessor and Successor periods to include a full year of results for the year ended December 31, 2012. We did not include any adjustments related to the application of fresh-start reporting for the year ended December 31, 2012. 

	2013		2012
(in millions)
Revenues	$	2,986.8	$	3,811.1
Net loss	$	(113.6)	$	(12.0)

Revenue and earnings for HIE subsequent to the acquisition are included in Note 17 - Segment Information. 

Assets Contributed to Piceance Energy

At December 31, 2011, Delta’s oil and gas assets were classified as held for use and no impairment charges resulted from the analysis performed at December 31, 2011 as the estimated undiscounted net cash flows exceeded carrying amounts for all properties. In August 2012, the Bankruptcy Court approved a plan of sale of substantially all of the Predecessor’s assets and accordingly these assets were classified as held for sale and an impairment of approximately $151.3 million was recognized for the period from January 1, 2012 through August 31, 2012 to write-down these assets to fair value due to the application of fresh-start reporting. The assets were then contributed to Piceance Energy in accordance with our Plan of Reorganization.

Assets Held for Sale

As of December 31, 2012, we classified certain compressors as held for sale, which were recorded at the lower of cost or estimated net realizable value. On February 20, 2013, these compressors were sold for approximately $2.9 million resulting in a gain of $50 thousand.

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Loss Per Share

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

Note 16 - Loss Per Share

The following table sets forth the computation of basic and diluted loss per share (in thousands, except per share amounts):

	Successor				Predecessor
			September 1		January 1
	Year Ended		through		through
	December 31,		December 31,		August 31,
	2013		2012		2012
Net loss attributable to common stockholders	$	(70,621)	$	(8,839)	$	(45,437)
Basic weighted-average common shares     outstanding		19,740		15,734		28,841
Add: dilutive effects of stock options and     unvested stock grants (1)		—		—		—
Diluted weighted-average common stock outstanding		19,740		15,734		28,841
Basic loss per common share attributable to     common stockholders:
Net loss (1)	$	(3.57)	$	(0.56)	$	(1.57)
Diluted loss per common share attributable to     common stockholders:
Net loss (1)	$	(3.57)	$	(0.56)	$	(1.57)

________________________________________________________

^{(1) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Therefore, we have utilized the basic weighted-average common shares outstanding to calculate both basic and diluted loss per share for all parties presented.}

Weighted average potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following (in thousands):

	Successor		Predecessor
		Period from	Period from
		September 1	January 1
	Year Ended	through	through
	December 31,	December 31,	August 31,
	2013	2012	2012
Stock issuable upon conversion of convertible notes	—	—	379
Stock options	—	—	150
Non-vested restricted stock	523	—	558
Total potentially dilutive securities	523	—	1,087

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Defined Contribution Plans

12 Months Ended

Dec. 31, 2013

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Note 12 – Defined Contribution Plans

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 year ended December 31, 2013, we made contributions to the plans totaling approximately $502 thousand. There were no such plans in place for the period from September 1, 2012 through December 31, 2012.

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Commitments and Contingencies (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Commitment And Contingencies [Line Items]
2014	$ 382
2015	382
2016	382
2017	382
2018	420
Thereafter	420
Total minimum lease payments	2,368
Less amount representing interest	634
Total minimum rental payments	$ 1,734

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Intangible assets

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets Disclosure [Text Block]

Note 8 – Intangible assets

Our intangible assets consist of the following (in thousands):

	December 31,
	2013		2012
Amortized intangible assets:
Gross carrying amount:
Supplier relationships	$	3,360	$	3,360
Rail car leases		3,249		3,249
Historical shipper status		2,200		2,200
Trade names and trademarks		4,689		—
Subtotal		13,498		8,809
Accumulated amortization
Supplier relationships		(258)		—
Rail car leases		(650)		—
Historical shipper status		(1,100)		—
Trade name and trademarks		(320)		—
Subtotal		(2,328)		—
Net:
Supplier relationships		3,102		3,360
Rail car leases		2,599		3,249
Historical shipper status		1,100		2,200
Trade name and trademarks		4,369		—
Total amortized intangible assets, net	$	11,170	$	8,809

Amortization expense was approximately $2.3 million for the year ended December 31, 2013. There was no amortization expense during 2012. Expected future amortization expense for each of the next five years and thereafter is as follows (in thousands):

Year Ended	Amount
2014	$	3,571
2015		2,471
2016		2,151
2017		908
2018		258
Thereafter		1,811
	$	11,170

During the year ended December 31, 2013 the changes in the carrying amount of goodwill for the year ended December 31, 2013 were as follows (in thousands):

Balance at beginning of period	$	7,756
Additions		13,613
Texadian purchase price adjustments		(766)
Balance at end of period	$	20,603

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Inventories (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Crude oil and feedstocks	$ 146,158
Refined products and blend stock	229,086
Spare parts, materials and supplies, and merchandise	13,831
Inventory, Net, Total	389,075	10,466
Titled Inventory [Member]
Crude oil and feedstocks	0	10,466
Refined products and blend stock	67,532	0
Spare parts, materials and supplies, and merchandise	13,831	0
Inventory, Net, Total	81,363	10,466
Supply and Exchange Agreements [Member]
Crude oil and feedstocks	146,158
Refined products and blend stock	161,554
Spare parts, materials and supplies, and merchandise	0
Inventory, Net, Total	$ 307,712

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Information Regarding Proved Oil and Gas Reserves (Details 2) (USD $) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended	4 Months Ended	12 Months Ended	4 Months Ended	12 Months Ended	8 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012 Company	Dec. 31, 2013 Company	Dec. 31, 2012 Company's Share of Piceance Energy [Member]	Dec. 31, 2013 Company's Share of Piceance Energy [Member]	Aug. 31, 2012 Predecessor [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Beginning of the period	$ 7,223	$ 79,969	$ 7,223	$ 8,010	$ 0	$ 71,959	$ 129,695
Transfer from investees	55,253		0		55,253		0
Sales of oil and gas production during the period, net of production costs	(4,095)	(12,522)	(456)	(2,044)	(3,639)	(10,478)	(5,954)
Net change in prices and production costs	(806)	(6,421)	(667)	(3,833)	(139)	(2,588)	378
Changes in estimated future development costs	5	8,831	0	0	5	8,831	0
Extensions, discoveries and improved recovery	1,332	15,618	763	147	569	15,471	0
Revisions of previous quantity estimates, estimated timing of development and other	14,356	(4,553)	648	395	13,708	(4,948)	(7,439)
Previously estimated development and abandonment costs incurred during the period		3,142		0		3,142
Sales/disposition of reserves in place	0		0		0		(118,104)
Other	4,618	801	258	61	4,360	740	0
Accretion of discount	2,083	7,997	241	801	1,842	7,196	8,647
End of period	$ 79,969	$ 92,862	$ 8,010	$ 3,537	$ 71,959	$ 89,325	$ 7,223

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

Note 6 – Asset Retirement Obligations

The following is a reconciliation of our AROs (in thousands):

	Successor				Predecessor
			September 1		January 1
	Year Ended		through		through
	December 31, 2013		December 31, 2012		August 31, 2012
Asset retirement obligation –     beginning of period	$	512	$	476	$	3,799
Obligation acquired		2,601		—		—
Accretion expense		59		36		178
Change in estimate		—		—		437
Settlement upon transfer to     Piceance Energy		—		—		(3,938)
Asset retirement obligation –     end of period	$	3,172	$	512	$	476

As the result of the contribution of assets to Piceance Energy during the reorganization, approximately $3.9 million of our AROs was deemed settled as of the Emergence Date.

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Inventories

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Inventory Disclosure [Text Block]

Note 7 - Inventories

The following is a summary of our inventory (in thousands):

								December 31,
	December 31, 2013							2012
				Supply and
		Titled		Exchange
		Inventory		Agreements		Total		Titled Inventory
Crude oil and feedstocks	$	—	$	146,158	$	146,158	$	10,466
Refined products and blend stock		67,532		161,554		229,086		—
Spare parts, materials and supplies, and merchandise		13,831		—		13,831		—
	$	81,363	$	307,712	$	389,075	$	10,466

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Supply and Exchange Agreements

12 Months Ended

Dec. 31, 2013

Supply And Exchange Agreements [Abstract]

Supply And Exchange Agreements [Text Block]

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. We entered into the Supply and Exchange Agreements 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. Additionally, Barclays 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 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 volumes at period-end in excess of the Block Volume, we record a liability for the Block Volume valued at the per barrel carrying value of the refined product inventory owned by Barclays. From time to time, we may sell refined product inventory that causes our refined product inventory to be less than the Block Volume. To the extent of this shortfall, we record a liability for the volumes that we would need to purchase at current market prices in order to meet the Block Volume requirement. The liability related to the Supply and Exchange Agreements is included in obligations under supply and exchange agreements on our consolidated balance sheet.

For the year ended December 31, 2013, we incurred approximately $3.7 million in handling fees related to the Supply and Exchange Agreements, which is included in cost of revenues on our consolidated statement of operations. F or the year ended December 31, 2013, interest expense and financing costs, net includes $1.4 million of expense related to the Supply and Exchange Agreements.

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Intangible assets (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	$ 2,300,000	$ 0

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Commitments and Contingencies (Details 2) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Commitment And Contingencies [Line Items]
2014	$ 22,724
2015	13,277
2016	12,362
2017	10,375
2018	9,244
Thereafter	25,614
Operating Leases, Future Minimum Payments Due, Total	$ 93,596

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Debt (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Total debt, net of unamortized debt discount	$ 97,280	$ 42,391
Less: current maturities	(3,250)	(35,000)
Long term debt, net of current maturities and unamortized discount	94,030	7,391
Delayed Draw Term Loan Agreement [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	0	13,465
Unamortized Debt Discount - Warrants [Member]
Debt Instrument [Line Items]
Unamortized Debt Discount	0	(6,014)
Unamortized Debt Discount - Embedded Derivative [Member]
Debt Instrument [Line Items]
Unamortized Debt Discount	0	(60)
ABL Facility [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	51,800	0
Retail Credit Agreement [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	26,000	0
Tranche B Loan [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	$ 19,480	$ 35,000

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Reorganization Under Chapter 11, Fresh-Start Reporting and the Effects of the Plan (Details Textual) (USD $)	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2012	Aug. 31, 2012	Dec. 31, 2013
Reorganization [Line Items]
Common Stock Shares Issued	15,008,092		30,151,000
Class Of Warrant Or Right Number Of Securities Called By Warrants Or Rights			959,213
Share Price	$ 12.00		$ 22.30
Gains Losses On Extinguishment Of Debt	$ 0		$ 0
Fresh Start Adjustments Pretax Loss		14,800,000
Settlement Of Other Claims [Member]
Reorganization [Line Items]
Common Stock Shares Issued		191,973
Share Price		$ 7.00
Gains Losses On Extinguishment Of Debt		2,200,000
Secured Debt [Member]
Reorganization [Line Items]
Common Stock Shares Issued		14,573,608
Class Of Warrant Or Right Number Of Securities Called By Warrants Or Rights		959,213
Share Price		$ 7.00
Gains Losses On Extinguishment Of Debt		166,100,000
Reorganized Delta Petroleum [Member]
Reorganization [Line Items]
Line Of Credit Facility Amount Outstanding		13,000,000
Piceance Energy [Member]
Reorganization [Line Items]
Equity Method Investment Ownership Percentage		33.34%	33.34%
Line Of Credit Facility Amount Outstanding		100,000,000	90,200,000
Equity Method Investments Fair Value Disclosure		105,300,000
Piceance Energy [Member] | Laramie
Reorganization [Line Items]
Equity Method Investment Ownership Percentage		66.66%
Debtor In Possession Financing Amount Arranged		24,900,000
Piceance Energy [Member] | Reorganized Delta Petroleum [Member]
Reorganization [Line Items]
Equity Method Investment Ownership Percentage		33.34%
Debtor In Possession Financing Amount Arranged		$ 72,600,000

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Intangible assets (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Goodwill [Line Items]
Balance at beginning of period	$ 7,756
Additions	13,613
Texadian purchase price adjustments	(766)
Balance at end of period	$ 20,603

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Income Taxes (Details 1)	4 Months Ended	12 Months Ended	8 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Aug. 31, 2012 Predecessor [Member]
Income Tax Rate Reconciliation [Line Items]
Federal statutory rate	(35.00%)	(35.00%)	(35.00%)
State income taxes, net of federal benefit	0.00%	0.10%	0.00%
Change in valuation allowance	(2.00%)	21.70%	(33.00%)
Professional fees related to bankruptcy reorganization	8.00%	0.00%	17.00%
Revenue from Wapiti Trust settlement	5.00%	0.00%	0.00%
Cancellation of debt tax attribute reduction	0.00%	0.00%	51.00%
Permanent Items	0.00%	4.10%	0.00%
Provision to return adjustments	0.00%	9.10%	0.00%
Actual income tax rate	(24.00%)	0.00%	0.00%

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

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

	December 31,
	2013		2012
Land	$	39,800	$	—
Buildings and equipment		65,878		—
Other		1,945		1,415
Property, plant and equipment		107,623		1,415
Proved oil and gas properties		4,949		4,804
Less: accumulated depreciation, depletion     and amortization		(3,968)		(373)
	$	108,604	$	5,846

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Investment in Piceance Energy (Details) (USD $) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Beginning balance		$ 104,434
Loss from unconsolidated affiliates		(2,941)
Ending balance		101,796
Piceance Energy [Member]
Schedule of Equity Method Investments [Line Items]
Beginning balance	105,344	104,434
Loss from unconsolidated affiliates	(1,325)	(3,516)
Accretion of basis difference	0	575
Capitalized drilling costs obligation paid	415	303
Ending balance	$ 104,434	$ 101,796

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Stockholders' Equity

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Stockholders Equity Note Disclosure [Text Block]

Note 14 - Stockholders’ Equity

Pursuant to the Plan, on the Emergence Date, (i) all shares of our common stock outstanding prior to the Effective Date were cancelled, (ii) each holder of our 7% senior unsecured notes due 2015 and our 3 ³/₄% senior convertible notes due 2037 received, in exchange for its total claim (including principal and interest), its pro rata portion of 14,573,608 shares of our common stock, (iii) each holder of an allowed general unsecured claim received, in exchange for its total claim, its pro rata portion of 191,973 shares of our common stock, and (iii) the Lenders under the Loan Agreement received warrants to purchase up to an aggregate of 959,213 shares of our common stock (which number of shares may be increased to an aggregate of 1,220,000 shares of our common stock pursuant to the terms of the Warrant Issuance Agreement).  

Amendments to the Certificate of Incorporation and Bylaws

Pursuant to the Plan, on the Emergence Date, our certificate of incorporation and bylaws were amended and restated in their entirety.

Under the restated certificate of incorporation, the total number of all shares of capital stock that we are authorized to issue is 303 million shares, consisting of 300 million shares of common stock and 3 million shares of preferred stock, par value $0.01 per share. The restated 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 Code, of us or any direct or indirect subsidiary thereof.

On November 25, 2013, our amended and restated certificate of incorporation was further amended to (i) increase the authorized shares of Common Stock from 300,000,000 to 500,000,000 and (ii) revise certain provisions regarding approval by the company’s Board of Directors of transfers of Common Stock by holders of five percent or more of the outstanding Common Stock.

Preferred Stock

As of December 31, 2013 and 2012, no shares of preferred stock were outstanding.

Common Stock

On December 31, 2012, a total of 3,052 shares of our common stock were issued to members of our Board of Directors in lieu of a cash fee for their service on the Board. We recognized compensation costs of approximately $33 thousand relating to these shares, which represent their estimated fair value on the date of grant based on the previous 20 days average trading price of our common stock which ranged from $10.00 to $12.00 per share of common stock. Due to our limited daily trading activity, we believe that this represents a more accurate reflection of the fair value of our common stock.

On September 13, 2013, we entered into a Common Stock Purchase Agreement pursuant to which we agreed to sell shares of our common stock at a price of $13.90 per share, as adjusted to reflect the one for ten reverse stock split effective for trading purposes on January 29, 2014 (the “Reverse Stock Split”),  in a private placement transaction (the “Private Placement”) in reliance upon an exemption from registration pursuant to Regulation D under the Securities Act of 1933. Certain purchasers, namely, ZCOF Par Petroleum Holdings, L.L.C., an affiliate of Zell Credit Opportunities Master Fund, L.P. (“ZCOF”), and affiliates of Whitebox Advisors, LLC (“Whitebox”), each owned 10% or more of the our common stock directly or through affiliates prior to the execution of the Common Stock Purchase Agreement and are deemed to be our affiliates as a result of such ownership. ZCOF and Whitebox have representatives on our board of directors.

On September 25, 2013, we completed the Private Placement and issued approximately 14.4 million shares of common stock resulting in aggregate gross proceeds to us of approximately $200 million. We did not engage any investment advisors with respect to the Private Placement, and no finders’ fees or commissions were paid to any party in connection therewith. The proceeds from the Private Placement were used to fund a portion of the purchase price of the HIE acquisition.

During the year ended December 31, 2013, we issued approximately 208,512 shares of our common stock for settlement of bankruptcy claims, approximately 183,390 shares due to the exercise of Warrants and approximately 5,585 shares of unrestricted common stock to certain key employees and directors. We recognized compensation costs of approximately $90 thousand relating to these shares, which represent their estimated fair value on the date of grant based on the previous 20 days average trading price of our common stock which ranged from $12.22 to $19.87 per share of common stock.

Registration Rights Agreements

Pursuant to the Plan, on the Effective Date, we entered into a registration rights agreement (the “Registration Rights Agreement”) providing the stockholders party thereto (the “Stockholders”) with certain registration rights.

The Registration Rights Agreement states that, among other things, at any time after the earlier of the consummation of a qualified public offering or 60 days after the Effective Date, 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 on Form S-1 or S-3, or any other appropriate form under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, 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, on any form for which we then qualify and which is available for the sale of the Registrable Shares in accordance with the intended methods of distribution thereof, with respect to the Demand Registration. We are required to use commercially reasonable efforts to cause the registration statement to be declared effective as soon as practicable after such filing. We will not be obligated (i) to effect a Demand Registration within 90 days after the effective date of a previous Demand Registration, other than for a shelf registration, or (ii) to effect a Demand Registration unless the Demand Request is for a number of Registrable Shares with an expected market value that is equal to at least (x) $15 million as of the date of such Demand Request or is for one hundred percent of the demanding Stockholder’s Registrable Shares with respect to any Demand Registration made on Form S-1 or (y) $5 million as of the date of such Demand Request with respect to any Demand Registration made on Form S-3.

Upon receipt of any Demand Request, we are required to give written notice, within ten (10) days of such Demand Registration, to all other holders of Registrable Shares, who will have the right to elect to include in such Demand Registration such portion of their Registrable Shares as they may request, subject to certain exceptions.

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.

The rights of a holder of Registrable Shares may be transferred, assigned or otherwise conveyed on to any transferee or assignee of such Registrable Shares, subject to applicable state and federal securities laws and regulations, our Certificate of Incorporation and the Stockholders Agreement. We will be responsible for expenses relating to the registrations contemplated by the Registration Rights Agreement.

The registration rights granted in the Registration 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.

In connection with the closing of the sale of the 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 U.S. Securities and Exchange Commission 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.

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. We will accrue an obligation for this registration rights agreement when it is probable that an obligation has been incurred and the amount can be reasonably determined.

Incentive Plan

On December 20, 2012, our Board of Directors (the “Board”) approved the Par Petroleum Corporation 2012 Long Term Incentive Plan (the “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. In addition, in December 2012, we approved a new compensation plan for our directors. Our directors receive an annual retainer of $50 thousand, paid quarterly in cash or shares of our common stock at the election of the director. In addition, the Chairman of the Audit Committee receives an additional annual retainer of $15 thousand and the members of the Audit Committee (other than the Chairman) receive an annual retainer of $5 thousand, such retainers paid quarterly in cash or shares of our common stock at the election of the director. There are no fees for the members of any other committee or for attendance at meetings. Our directors are also entitled to receive an annual grant of restricted stock on the last day of each calendar year with a target value of $75 thousand, with the number of shares determined by the 60-day volume weighted average share price as of the day prior to the grant date.

On December 31, 2012, a total of 219,183 shares of restricted common stock were granted to members of the Board of Directors and certain employees. During the year ended December 31, 2013, an additional 355,481 shares of restricted stock were granted to certain employees. Restricted stock granted to members of the Board vests in full after one year from the date of grant, while most restricted stock granted to employees vests on a pro-rata basis over five years. For the year ended December 31, 2013, the following activity occurred under our Incentive Plan (in thousands, except per share amounts):

	Shares	Weighted- Average Grant Date Fair Value
Non vested balance, beginning of period	219	$	12.00
Granted	356		18.32
Vested	(51)		12.00
Forfeited	—		—
Non vested balance, end of period	524	$	16.29
Available for grant	1,025

For the year ended December 31, 2013, we recognized compensation costs of approximately  $1.2 million related to restricted stock awards. As of December 31, 2013, there is approximately $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 4.37 years. The grant date fair value was estimated using the previous 20 days average trading price of our common stock.

Predecessor Stock Compensation Plans

On December 22, 2009, the Predecessor’s stockholders approved its 2009 Performance and Equity Plan (the “2009 Plan”). On June 21, 2011, the Predecessor granted 489,227 shares of non-vested common stock to certain employees. The shares vested in full on the earlier of a change in control or July 1, 2012. In conjunction with this grant, the Predecessor agreed to establish a “floor” price for the value of the shares on the date of vesting equal to the value of the shares on the grant date ($5.50 per share). In the event that the market price of the shares on the date of vesting was lower than the floor price on the date of vesting, the difference would be paid to the employees in cash. The compensation expense for the shares consists of a fixed equity component ($5.50 per share) and a variable liability component (based on the difference between the market price of the shares, if lower, and the floor price of the shares), both of which are included as a component of general and administrative expense in the accompanying Predecessor consolidated statement of operations. The Predecessor recognized stock compensation expense of approximately $1.9 million for the period from January 1, 2012 through August 31, 2012, which is included in general and administrative expenses. Under the terms of the Plan, the Predecessor’s stock compensation plans, and all awards issued under such plans, were canceled.

A summary of the stock option activity under the Predecessor’s various plans and related information for the period from January 1 through August 31, 2012 follows:

	Period from January 1 through August 31, 2012
	Options	Weighted-Average Exercise Price		Weighted-Average Remaining  Contractual Term	Aggregate Intrinsic Value
Outstanding-beginning of year	150,300	$	75.00
Granted	—		—
Exercised	—		—
Expired / canceled	(150,300)		(75.00)
Outstanding-end of year	—	$	—	—	$	—
Exercisable-end of year	—	$	—	—	$	—

A summary of the restricted stock (nonvested stock) activity under the Predecessor’s plan and related information for the period from January 1 through August 31, 2012 follows (in thousands, except share and per share amounts):

	Period from January 1 through August 31, 2012
	Nonvested Stock	Weighted-Average Grant-Date Fair Value		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
Nonvested-beginning of year	558,301	$	7.45
Granted	—		—
Vested	—		—
Expired / canceled	(558,301)		(7.45)
Nonvested-end of year	—	$	—	—	$	—

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Reorganization Under Chapter 11, Fresh-Start Reporting and the Effects of the Plan

12 Months Ended

Dec. 31, 2013

Reorganizations [Abstract]

Reorganization Under Chapter 11 Of U S Bankruptcy Code Disclosure [Text Block]

Note 19 - Reorganization Under Chapter 11, Fresh-Start Reporting and the Effects of the Plan 

In December 2011 and January 2012, Delta and its subsidiaries filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). Delta and its subsidiaries included in the bankruptcy petitions are collectively referred to as the “Debtors.”

In March 2012, the Bankruptcy Court approved the procedures relating to plans of reorganization as well as asset sales. Following completion of the asset sales, the Debtors obtained approval from the Bankruptcy Court to proceed with Laramie Energy II, LLC (“Laramie”) as the sponsor of a plan of reorganization (the “Plan”). In June 2012, Delta entered into a Contribution Agreement (the “Contribution Agreement”) with a new joint venture formed by Delta and Laramie, Piceance Energy LLC (“Piceance Energy”), and Laramie to effect the transactions contemplated by Plan.

The Plan was declared effective on August 31, 2012 (the “Emergence Date”). On the Emergence Date, Delta consummated the transaction contemplated by the Contribution Agreement and each of Delta and Laramie contributed to Piceance Energy their respective assets in the Piceance Basin. Piceance Energy is owned 66.66% by Laramie and 33.34% by Delta. At the closing, Piceance Energy entered into a new credit agreement, borrowed $100 million under that agreement, and distributed approximately $72.6 million net of settlements to the company and approximately $24.9 million to Laramie. The company used its distribution to pay bankruptcy expenses and to repay its secured debt. The company also entered into a new credit facility and borrowed $13 million under that facility at closing, and used those funds primarily to pay bankruptcy claims and expenses.

Following the reorganization, Par retained its interest in the Point Arguello Unit offshore California and other miscellaneous assets and certain tax attributes, including significant net operating loss carryforwards. Based upon the Plan as confirmed by the Bankruptcy Court, Delta’s creditors were issued approximately 14.8 million shares of common stock, and Delta’s former stockholders received no consideration under the Plan.

Contemporaneously with the consummation of the Contribution Agreement, the company, through a wholly-owned subsidiary, entered into a Limited Liability company Agreement with Laramie that will govern the operations of Piceance Energy.

On the Emergence Date, Par adopted fresh-start reporting resulting in us becoming a new entity for financial reporting purposes. Accordingly, our consolidated financial statements for periods prior to August 31, 2012 reflect the operations of Delta prior to reorganization (hereinafter also referred to as the “Predecessor”) and are not comparable to the consolidated financial statements presented on or after August 31, 2012. Fresh-start reporting was required upon emergence from Chapter 11 because (i) holders of voting shares immediately before confirmation of the Plan received less than 50% of the emerging entity and (ii) the reorganization value of our assets immediately before confirmation of the Plan was less than our post-petition liabilities and allowed claims. Fresh-start reporting results in a new basis of accounting and reflects the allocation of our estimated fair value to underlying assets and liabilities. The effects of the implementation of the Plan and fresh-start adjustments are reflected in the results of operations of the Predecessor in the eight month period ended August 31, 2012. Our estimates of fair value are inherently subject to significant uncertainties and contingencies beyond our reasonable control. Accordingly, there can be no assurance that the estimates, assumptions, valuations, appraisals and financial projections will be realized, and actual results could vary materially. Moreover, the market value of our common stock may differ materially from the equity valuation for accounting purposes.

In the application of fresh-start reporting, a successor entity must determine a value to be assigned to the equity of the emerging company as of the date of adoption of fresh-start reporting, which for us is August 31, 2012, the date the Debtors emerged from Chapter 11. To facilitate this calculation, we first determined the enterprise value of the Successor and the individual components of the opening balance sheet. The most significant item is our  33.34% interest in Piceance Energy, the value of which was estimated to be approximately $105.3 million as of the Emergence Date. We also considered the fair value of the other remaining assets. See Note 11 - Fair Value Measurements  for a detailed discussion of fair value and the valuation techniques.

The estimated enterprise value and the equity value are highly dependent on the achievement of the future financial results contemplated in the projections that were set forth in the Plan. The estimates and assumptions made in the valuation are inherently subject to significant uncertainties. The primary assumptions for which there is a reasonable possibility of the occurrence of a variation that would have significantly affected the reorganization value include the assumptions regarding our direct ownership of estimated proved reserves, our indirect ownership of estimated proved reserves through our equity ownership in Piceance Energy, operating expenses, the amount and timing of capital expenditures and the discount rate utilized.

Fresh-start reporting reflects the value of the Successor as determined in the confirmed Plan. Under fresh-start reporting, our asset values are remeasured and allocated based on their respective fair values in conformity with the acquisition method of accounting for business combinations. The reorganization values approximated the fair values of the identifiable net assets. Liabilities existing as of the Effective Date, other than deferred taxes and derivatives, were recorded at the present value of amounts expected to be paid using appropriate risk adjusted interest rates. Deferred taxes and derivatives were determined in conformity with applicable accounting standards. Predecessor accumulated depreciation, accumulated amortization and retained deficit were eliminated. Under the Plan, our priority non-tax claims and secured claims are unimpaired in accordance with the Bankruptcy Code. Each general unsecured claim and noteholder claims received its pro rata share of new common stock of Par in full satisfaction of its claims.

The following condensed consolidated balance sheet presents the implementation of the Plan and the adoption of fresh-start reporting as of the Effective Date. Reorganization adjustments have been recorded within the condensed consolidated balance sheet to reflect the effects of the Plan, including discharge of liabilities subject to compromise and the adoption of fresh-start reporting.

		August 31, 2012
				Plan of			Fresh Start
				Reorganization			Reporting
		Predecessor		Adjustments			Adjustments			Successor
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$	1,954	$	74,167	(a)	$			$	4,882
				(45,035)	(c)
				(24,204)	(d)
				(2,000)	(e)
Trust assets		—		3,446	(e)					3,446
Restricted cash		—		20,359	(d)					20,359
Trade accounts receivable, net		3,708		(1,727)	(a)		(1,981)	(g)		—
Prepaid assets		4,777					(4,777)	(g)		—
Prepaid reorganization costs		1,326					(1,326)	(g)		—
Total current assets		11,765								28,687
Property and equipment
Oil and gas properties
Unproved		84					(84)	(g)		—
Proved		759,755		(740,392)	(a)		(14,776)	(g)		4,587
Land		4,000		(4,000)	(a)					—
Other		73,021		(47,493)	(a)		(21,289)	(g)		4,239
Total property and equipment		836,860								8,826
Less accumulated depreciation and depletion		(642,172)		607,603	(a)		34,569	(g)		—
Property and equipment, net		194,688								8,826
Long-term assets:
Investments in unconsolidated affiliates		3,629		105,344	(a)		(3,629)	(g)		105,344
Other long-term assets		307					(253)	(g)		54
Total long-term assets		3,936								105,398
Total assets	$	210,389							$	142,911
LIABILITIES AND EQUITY
Current liabilities
Liabilities not subject to compromise
Debtor in possession financing	$	56,535		(56,535)	(c)				$	—
Accounts payable and other accrued liabilities		4,897								4,897
Other accrued liabilities		9,224		(2,685)	(b)					2,640
				(1,500)	(c)
				(3,845)	(d)
				1,446	(e)
Accrued reorganization and trustee expense		70,656								7,537
Liabilities subject to compromise
3 3/4% Senior notes		115,000		(115,000)	(b)					—
7% Senior convertible notes		150,000		(150,000)	(b)					—
Accounts payable and other accrued liabilities		17,203		(2,560)	(a)		(1,981)	(g)		12,336
				(3,526)	(d)		3,200	(g)
Total current liabilities		352,859								19,873
Long-term liabilities
Liabilities not subject to compromise
Long – term debt		—		6,335	(c)					6,335
Derivative liabilities		—		6,665	(c)					6,665
Asset retirement obligations		4,414		(3,938)	(a)					476
Total liabilities		357,273								33,349
Stockholders’ equity
Common stock		288		1,457	(b)		(288)	(f)		1,477
				20	(d)
Additional paid-in capital		1,643,285		100,084	(b)		288	(f)		108,085
				1,318	(d)		(1,636,890)	(h)
Retained earnings (accumulated deficit)		(1,790,457)		166,144	(b)		(14,765)	(g)		—
				2,188	(d)		1,636,890	(h)
Total stockholders’ equity (deficit)		(146,884)								109,562
Total liabilities and equity (deficit)	$	210,389							$	142,911

Notes to Plan of Reorganization and Fresh Start Accounting Adjustments

(a)	Reflects the contribution of certain of our oil and gas assets and related prepaid expenses and asset retirement obligations to Piceance Energy in exchange for cash and a 33.34% interest in Piceance Energy.
(b)	Reflects the extinguishment of secured debt in exchange for common stock of the Successor. On the Emergence Date, we issued 14,573,608 shares of our common stock and warrants to acquire 959,213 shares of our common stock to the holders of our secured debt or their affiliates. We estimated the fair value of our common stock to be $7.00 per share on the Emergence Date. Accordingly, we recorded a gain on the settlement of secured debt within Reorganization items of approximately $166.1 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
(c)	Reflects the Successor drawing $13 million under the Loan Agreement (see Note 10 - Debt) to repay amounts outstanding under the DIP Credit Facility with those proceeds and cash from contribution of assets to Piceance Energy.
(d)	Reflects the settlement of other claims with common stock of Successor and cash. On the Emergence Date, we issued 191,973 shares of our common stock to various creditors. We estimated the fair value of our common stock to be $7.00 per share on the Emergence Date. Accordingly, we recorded a gain on settlement of liabilities within Reorganization items of approximately $2.2 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
(e)	Reflects the funding of the Recovery Trusts (see Note 13 - Commitments and Contingencies).
(f)	Reflects the cancellation of Predecessor common stock.
(g)	Reflects adjustments to remaining assets due to fresh-start reporting. On the Emergence Date, we adjusted the carrying value of our remaining assets to their estimated fair values. As a result of these adjustments, we recorded a loss for changes in asset fair values due to fresh-start reporting adjustments within Reorganization items of approximately $14.8 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
(h)	Reflects the elimination of Predecessor’s accumulated deficit.

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Loss Per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	4 Months Ended		12 Months Ended		8 Months Ended
	Dec. 31, 2012		Dec. 31, 2013		Aug. 31, 2012 Predecessor [Member]
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Net loss attributable to common stockholders	$ (8,839)		$ (70,621)		$ (45,437)
Basic weighted-average common shares outstanding	15,734		19,740		28,841
Add: dilutive effects of stock options and unvested stock grants	0	[1]	0	[1]	0	[1]
Diluted weighted-average common stock outstanding	15,734		19,740		28,841
Basic loss per common share attributable to common stockholders:
Net loss	$ (0.56)	[1]	$ (3.57)	[1]	$ (1.57)	[1]
Diluted loss per common share attributable to common stockholders:
Net loss	$ (0.56)	[1]	$ (3.57)	[1]	$ (1.57)	[1]

[1] Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Therefore, we have utilized the basic weighted-average common shares outstanding to calculate both basic and diluted loss per share for all parties presented.

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Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2013
Refining [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	8 years
Refining [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	47 years
Logistic [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Logistic [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years
Retail [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	14 years
Retail [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	18 years
Corporate [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Corporate [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	7 years
Software [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years

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Disclosures About Capitalized Costs, Costs Incurred (Details 1) (USD $) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended	4 Months Ended		12 Months Ended		8 Months Ended
	Dec. 31, 2012 Company [Member]	Dec. 31, 2013 Company [Member]	Dec. 31, 2012 Company's Share of Piceance Energy [Member]		Dec. 31, 2013 Company's Share of Piceance Energy [Member]		Aug. 31, 2012 Predecessor [Member] Company [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved properties acquisition costs			$ 206		$ 0
Proved properties acquisition costs			32,519	[1]	0	[1]
Development costs incurred on proved undeveloped reserves	0	0					1,613
Development costs-other	0	142	291		6,380		0
Total	$ 0	$ 142	$ 33,016		$ 6,380		$ 1,613

[1] Amount represents our share of proved oil and natural gas property acquired at inception of the formation of Piceance Energy of which $24.2 million relates to oil and natural gas properties purchased from Delta contemplated as part the emergence from bankruptcy and $8.3 million relates oil and natural gas properties purchased from Laramie.

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Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Schedule Of Equity Incentive Plan Disclosures [Table Text Block]

For the year ended December 31, 2013, the following activity occurred under our Incentive Plan (in thousands, except per share amounts):

	Shares	Weighted- Average Grant Date Fair Value
Non vested balance, beginning of period	219	$	12.00
Granted	356		18.32
Vested	(51)		12.00
Forfeited	—		—
Non vested balance, end of period	524	$	16.29
Available for grant	1,025

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

A summary of the stock option activity under the Predecessor’s various plans and related information for the period from January 1 through August 31, 2012 follows:

	Period from January 1 through August 31, 2012
	Options	Weighted-Average Exercise Price		Weighted-Average Remaining  Contractual Term	Aggregate Intrinsic Value
Outstanding-beginning of year	150,300	$	75.00
Granted	—		—
Exercised	—		—
Expired / canceled	(150,300)		(75.00)
Outstanding-end of year	—	$	—	—	$	—
Exercisable-end of year	—	$	—	—	$	—

Schedule of Nonvested Share Activity [Table Text Block]

A summary of the restricted stock (nonvested stock) activity under the Predecessor’s plan and related information for the period from January 1 through August 31, 2012 follows (in thousands, except share and per share amounts):

	Period from January 1 through August 31, 2012
	Nonvested Stock	Weighted-Average Grant-Date Fair Value		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
Nonvested-beginning of year	558,301	$	7.45
Granted	—		—
Vested	—		—
Expired / canceled	(558,301)		(7.45)
Nonvested-end of year	—	$	—	—	$	—

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Disclosures About Capitalized Costs, Costs Incurred (Details Textual) (USD $) In Thousands, unless otherwise specified	4 Months Ended	8 Months Ended
	Dec. 31, 2012	Aug. 31, 2012
Piceance Energy [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved properties acquisition costs	$ 24,200
Capitalized Exploratory Well Costs, Suspended, Percentage of Equity Interest		33.34%
Laramie [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved properties acquisition costs	$ 8,300

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (USD $) In Thousands	Total	Common Stock [Member]	Additional Paid In Capital [Member]	Retained Earnings [Member]	Predecessor [Member]	Predecessor [Member] Common Stock [Member]	Predecessor [Member] Additional Paid In Capital [Member]	Predecessor [Member] Retained Earnings [Member]
Balance at Dec. 31, 2011					$ 50,225	$ 288	$ 1,641,390	$ (1,591,453)
Balance (in shares) at Dec. 31, 2011						28,841
Forfeitures					0	0	0	0
Forfeitures (in shares)						(58)
Cancellation of predecessor common stock	0	(288)	288	0
Cancellation of predecessor common stock (in shares)		(28,783)
Elimination of predecessor accumulated deficit	0	0	(1,636,890)	1,636,890
Issuance of common stock and fresh start accounting upon emergence from Chapter 11	102,879	148	102,731	0
Issuance of common stock and fresh start accounting upon emergence from Chapter 11 (in shares)		14,766
Stock issued to settle bankruptcy claims					0
Stock-based compensation					1,895	0	1,895	0
Net loss					(45,437)	0	0	(45,437)
Balance at Aug. 31, 2012	109,562	148	109,414	0	6,683	288	1,643,285	(1,636,890)
Balance (in shares) at Aug. 31, 2012		14,766				28,783
Stock issued to settle bankruptcy claims	0	0	0	0
Stock issued to settle bankruptcy claims (in shares)		20
Stock-based compensation	34	2	32	0
Stock-based compensation (in shares)		222
Net loss	(8,839)	0	0	(8,839)
Balance at Dec. 31, 2012	100,757	150	109,446	(8,839)
Balance (in shares) at Dec. 31, 2012		15,008
Stock issued to settle bankruptcy claims	2,605	2	2,603	0
Stock issued to settle bankruptcy claims (in shares)		209
Stock issued in a private transaction, net of offering cost of $830	199,170	144	199,026	0
Stock issued in a private transaction, net of offering cost of $830 (in shares)		14,388
Stock-based compensation	1,164	3	1,161	0
Stock-based compensation (in shares)		362
Stock issued through exercise of warrants	3,741	2	3,739	0
Stock issued through exercise of warrants (in shares)		184
Net loss	(70,621)	0	0	(70,621)
Balance at Dec. 31, 2013	$ 236,816	$ 301	$ 315,975	$ (79,460)
Balance (in shares) at Dec. 31, 2013		30,151

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Stockholders' Equity (Details 1) (Predecessor [Member], USD $)	8 Months Ended
	Aug. 31, 2012
Predecessor [Member]
Options
Outstanding-beginning of year	150,300
Granted	0
Exercised	0
Expired / canceled	(150,300)
Outstanding-end of year	0
Exercisable-end of year	0
Weighted-Average Exercise Price
Outstanding-beginning of year	$ 0
Granted	$ 0
Exercised	$ 0
Expired / canceled	$ 0
Outstanding-end of year	$ 0
Exercisable-end of year	$ 0
Weighted-Average Remaining Contractual Term
Outstanding-end of year	0 years
Exercisable-end of year	0 years
Aggregate Intrinsic Value
Outstanding-end of year	$ 0
Exercisable-end of year	$ 0

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Investment in Piceance Energy

12 Months Ended

Dec. 31, 2013

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments Disclosure [Text Block]

Note 3 - Investment in Piceance Energy

We account for our 33.34% ownership interest in Piceance Energy using the equity method of accounting because we are able to exert significant influence but do not control the operating and financial policies. The Piceance Energy  LLC Agreement provides that its sole manager may make a written capital call such that each member shall make additional capital contributions up to an aggregate combined total capital contribution of $60 million ($20 million to our interest), if approved by a majority of its board. If any member does not fund its share of the capital call, its interest may be reduced or diluted by the amount of the shortfall. In addition, Piceance Energy has a $400 million secured revolving credit facility secured by a lien on its natural gas and oil properties and related assets with a borrowing base currently set at $120 million.  As of December 31, 2013, the balance outstanding on the revolving credit facility was approximately $90.2 million. We are guarantors of Piceance Energy’s credit facility, with recourse limited to the pledge of our equity interests of Par Piceance Energy. Under the terms of its credit facility, Piceance Energy is generally prohibited from making future cash distributions to its owners, including us.

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

			September 1
	Year Ended		through
	December 31, 2013		December 31, 2012
Beginning balance	$	104,434	$	105,344
Loss from unconsolidated affiliates		(3,516)		(1,325)
Accretion of basis difference		575		—
Capitalized drilling costs obligation paid		303		415
Ending balance	$	101,796	$	104,434

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

	December 31, 2013		December 31, 2012
Assets
Current assets	$	5,901	$	6,275
Non-current assets		454,402		460,991
Current liabilities		(13,040)		(11,826)
Non-current liabilities		(96,738)		(94,369)

	Year Ended		September 1 through
	December 31, 2013		December 31, 2012
	100%		100%
Oil, natural gas and natural gas liquids     revenues	$	61,091	$	19,391
Loss from operations		(6,765)		(2,095)
Net loss		(10,546)		(3,975)

The net loss for the year ended December 31, 2013 includes $26.6 million and $770 thousand in DD&A expense and losses on derivative instruments, respectively. The net loss for the period from September 1 through December 31, 2012 include $8.5 million and $917 thousand of DD&A expense and losses on derivative instruments, respectively.

At December 31, 2013 and 2012, our equity in the underlying net assets of Piceance Energy exceeded the carrying value of our investment by approximately $15.1 million and $15.9 million, respectively. This difference arose due to lack of control and marketability discounts and we attributed it to natural gas and oil properties and will amortize the difference over 15 years based on the estimate of proved reserves at the date Piceance Energy was formed.

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended	8 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Aug. 31, 2012 Predecessor [Member]
Asset Retirement Obligations [Line Items]
Asset retirement obligation - beginning of period	$ 476	$ 512	$ 3,799
Obligation acquired	0	2,601	0
Accretion expense	36	59	178
Change in estimate	0	0	437
Settlement upon transfer to Piceance Energy	0	0	(3,938)
Asset retirement obligation - end of period	$ 512	$ 3,172	$ 476

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Defined Contribution Plans (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	3.00%
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage	6.00%
Defined Contribution Plan, Cost Recognized	$ 0
Defined Benefit Plan, Benefit Obligation, Period Increase (Decrease)	$ 502,000
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	5.50%
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	8.50%

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Disclosures About Capitalized Costs, Costs Incurred (Details 2) (USD $) In Thousands, unless otherwise specified	4 Months Ended	12 Months Ended	4 Months Ended	12 Months Ended	4 Months Ended	12 Months Ended	8 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012 Company [Member]	Dec. 31, 2013 Company [Member]	Dec. 31, 2012 Company's Share of Piceance Energy [Member]	Dec. 31, 2013 Company's Share of Piceance Energy [Member]	Aug. 31, 2012 Predecessor [Member]	Aug. 31, 2012 Predecessor [Member] Company [Member]
Revenue:
Oil and gas revenues	$ 2,144	$ 7,739	$ 2,144	$ 7,739	$ 6,464	$ 20,364	$ 23,079	$ 23,079
Expenses:
Production costs			1,688	5,696	3,033	9,885		16,980
Depletion and amortization			370	1,593	2,808	8,855		16,041
Exploration			0	0				2
Abandoned and impaired properties			0	0				151,347
Results of operations of oil and gas producing activities			86	450	623	1,624		(161,291)
Total Company and Piceance Energy income from operations of oil and gas producing activities					$ 709	$ 2,074

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Debt (Details 3)	12 Months Ended
	Dec. 31, 2013
Leverage Ratio Less Than 4.00 [Member] | LIBOR loans [Member]
Debt Instrument [Line Items]
Debt Instrument Margin Rate	2.00%
Leverage Ratio Less Than 4.00 [Member] | Base Rate Loans [Member]
Debt Instrument [Line Items]
Debt Instrument Margin Rate	0.00%
Leverage Ratio 4.00-5.00 [Member] | LIBOR loans [Member]
Debt Instrument [Line Items]
Debt Instrument Margin Rate	2.25%
Leverage Ratio 4.00-5.00 [Member] | Base Rate Loans [Member]
Debt Instrument [Line Items]
Debt Instrument Margin Rate	0.25%
Leverage Ratio Grater Than 5.00 [Member] | LIBOR loans [Member]
Debt Instrument [Line Items]
Debt Instrument Margin Rate	2.50%
Leverage Ratio Grater Than 5.00 [Member] | Base Rate Loans [Member]
Debt Instrument [Line Items]
Debt Instrument Margin Rate	0.50%

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Subsequent Events

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Note 20 - Subsequent Events

On the January 23, 2014 and in connection with the consummation of the Reverse Stock Split as described in Note 1-Overview, we and certain of our subsidiaries entered into an Eleventh Amendment to our Loan Agreement pursuant to which the Lender consented to Fractional Share Cash Payments.

As a result of the Reverse Stock Split, every ten pre-split shares of Common Stock issued prior to January 29, 2014, the effective date of the reverse stock split for trading purposes, were exchanged for one post-split share of Common Stock, with fractional shares paid in cash at an amount equal to the product obtained by multiplying (a) the closing price of the Common Stock as reported on the OTCQB Marketplace on January 23, 2014, by (b) the fraction of one share owned by the stockholder. Further, the number of shares of Common Stock issued and outstanding was reduced from approximately 301,141,520 on January 23, 2014 to approximately 30,114,352. The number of authorized shares of Common Stock will remain at 500,000,000 and the par value of the Common Stock will remain at $0.01 per share. 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 outstanding prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis, unless otherwise noted. No adjustments have been made to the share or per share amounts of our Predecessor.

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Fair Value Measurements (Details 2) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Sep. 25, 2013 Purchase Price Allocation of HIE [Member]		Sep. 25, 2013 Purchase Price Allocation of HIE [Member] Property, Plant and Equipment, Other Types [Member]		Sep. 25, 2013 Purchase Price Allocation of HIE [Member] Land [Member]
Net working capital			$ 462,059	[1]
Property, Plant, and Equipment, Fair Value Disclosure					58,782	[2]	39,800	[3]
Trade names and trade marks			4,689	[4]
Goodwill			13,613	[5]
Other noncurrent liabilities			(6,384)	[6]
Contingent consideration liability	11,980	0	(11,980)	[7]
Fair Value, Net Asset (Liability), Total			$ 560,579

[1] Current assets acquired and liabilities assumed were recorded at their net realizable value.

[2] The estimated 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.

[3] The estimated 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.

[4] The estimated 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.

[5] The excess of the purchase price paid over the fair value of the identifiable assets acquired and liabilities assumed is allocated to goodwill.

[6] Other noncurrent assets and liabilities are recorded at their estimated net present value as estimated by management.

[7] The estimated 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.

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Debt (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule of Debt [Table Text Block]

Our debt is as follows (in thousands):

	December 31,
	2013		2012
Tranche B Loan	$	19,480	$	35,000
Delayed Draw Term Loan Agreement		—		13,465
ABL Facility		51,800		—
Retail Credit Agreement		26,000		—
Less: unamortized debt discount – warrants		—		(6,014)
Less: unamortized debt discount – embedded derivative		—		(60)
Total debt, net of unamortized debt discount		97,280		42,391
Less: current maturities		(3,250)		(35,000)
Long-term debt, net of current maturities and unamortized discount	$	94,030	$	7,391

Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block]

Annual maturities of our long-term debt are due during the following years (in thousands):

Year		Amount Due
2014	$	3,250
2015		2,600
2016		22,080
2017		54,400
2018		2,600
Thereafter		12,350
	$	97,280

Schedule of Maximum Leverage Ratio [Table Text Block]

Such covenants require HIE Retail to maintain a maximum Leverage Ratio (as defined in the Retail Credit Agreement) as follows:

Period (during and as of the last day of)	Maximum Leverage Ratio
2013 Fiscal Year	5.75 to 1.00
2014 Fiscal Year	5.50 to 1.00
2015 Fiscal Year	5.25 to 1.00
2016 Fiscal Year	5.00 to 1.00
2017 Fiscal Year, and at all times thereafter	4.75 to 1.00

Schedule Of Applicable Margin For Debt Instrument [Table Text Block]

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	%	0	%
2	4.00x-5.00x	2.25	%	.25	%
3	>5.00x	2.5	%	.50	%

Schedule Of Revolver Applicable Margin for Debt Instrument [Table Text Block]

The 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	.25	%	1.75	%	-.25	%
2	4.00x-5.00x	.375	%	2.00	%	0	%
3	>5.00x	.50	%	2.25	%	.25	%

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies Disclosure [Text Block]

Note 13 - Commitments and Contingencies

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.  

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.

Regulation of Greenhouse Gases. The United States Environmental Protection Agency (“US EPA”) has begun regulating greenhouse gases under the Clean Air Act Amendments of 1990 (the “Clean Air Act”).  New construction or material expansions that meet certain greenhouse gas emissions thresholds will likely require that, among other things, a greenhouse gas 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 greenhouse gas emissions.

Furthermore, the US EPA is currently developing refinery-specific greenhouse gas regulations and performance standards that are expected to impose, on new and modified operations, greenhouse gas 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.

In 2007, the State of Hawaii passed Act 234, which required that greenhouse gas emissions be rolled back on a state wide 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 greenhouse gas emissions were reported to the US 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 greenhouse gas 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 greenhouse gas 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 (the “RFS2”). In August 2012, the US 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 US  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 US 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 US 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 nation-wide 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.

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 (the “Closing Date”), Hawaii Pacific Energy (a wholly-owned subsidiary of Par created for purposes of the Tesoro Acquisition), Tesoro and HIE entered into an Environmental Agreement (the “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 US 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 (the “Consent Decree”), including the Hawaii refinery.  It is anticipated that the Consent Decree will be finalized sometime during 2014 and will require certain capital improvements to our refinery to reduce emissions of air pollutants.

It is not possible at this time to estimate the cost of compliance with the ultimate decree. 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 has agreed, at its expense, to replace the existing underground storage tanks at certain retail assets.

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 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 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.

Helicopter Litigation.

HIE is the defendant in a lawsuit styled State of Hawaii Department of Transportation Airports Division et al. v. Tesoro Hawaii, Civil No. 09-2253-09 JHC. In this matter, the insurance company for the State of Hawaii is seeking reimbursement of the attorney’s fees and costs incurred by outside council to defend against Tesoro Hawaii’s third-party complaints for contribution in three previously-settled underlying litigation matters. The underlying litigation was filed by three helicopter tour operators flying on the Island of Kauau. The helicopter tour operators allege bad jet fuel caused the formation of coking deposits in their engines which resulted in millions of dollars of repair costs and lost income. There were no in-flight issues.

Tesoro Hawaii filed third-party complaints against the State of Hawaii in each of the three underlying lawsuits alleging that any fuel issues arose from improper design and maintenance of the underground pipeline and dispensers owned and maintained by the State of Hawaii. The helicopter operators settled with the State of Hawaii, and Tesoro Hawaii and its aviation liability insurers subsequently settled with the helicopter operators.

The lawsuit alleges that the State of Hawaii was entitled to a defense and indemnity under the terms of its lease for the Tesoro Hawaii facility at the Lihue airport. The suit alleges defense costs of approximately $2 million in the underlying lawsuits. The State of Hawaii and its insurance company have since demanded $3.25 million. The issue at trial is ultimately whether Tesoro Hawaii owed a contractual duty to pay for the State of Hawaii’s defense against Tesoro Hawaii’s third-party complaints against the State of Hawaii for the State’s own negligence. The case is set for a bench trial in September 2014.

There is a companion lawsuit by the State of Hawaii and its insurance company against Tesoro Hawaii’s former liability insurer on the same issues. The Court previously held by way of a Motion for Summary Judgment that Tesoro Hawaii’s insurer had a duty to defend the State of Hawaii against Tesoro Hawaii’s third-party complaints. That matter is going to trial in July 2014 on the issue of damages only (e.g. the reasonable amount of attorney’s fees and costs the State of Hawaii is entitled to for the defense of the third-Party Complaints in the underlying lawsuits).

We do not believe that any loss relating to this litigation is probable. However, should any loss become probable before the end of the measurement period, such loss would be reflected as a purchase price adjustment relating to the HIE Acquisition.

Recovery Trusts

On the date we emerged from bankruptcy, or the Emergence Date, two trusts were formed; the Wapiti Recovery Trust (the “Wapiti Trust”) and the Delta Petroleum General Recovery Trust (the “General Trust,” and together with the Wapiti Trust, the “Recovery Trusts”). The Recovery Trusts were 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 Recovery Trusts were funded with $1.0 million each pursuant to the Plan.

In September 2012, the Wapiti Trust settled all causes of action against Wapiti Oil & Gas, LLC (“Wapiti Oil & Gas”). Wapiti Oil & Gas made a one-time cash payment in the amount of $1.5 million to the Wapiti Trust, as consideration for the release of claims against it. These proceeds were then distributed to us, along with funds remaining from the initial funding of the Wapiti Trust of approximately $1.0 million. The Wapiti Trust was liquidated during 2013.

The General Trust is pursuing all bankruptcy causes of action not otherwise vested in the Wapiti Trust, 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 (the “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.

From the Emergence Date through December 31, 2013, the Recovery Trusts have 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. The entire $5.2 million was released prior to December 31, 2012.

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, 2012, the Recovery Trustee settled 25 claims with an aggregate face amount of $6.6 million for approximately $259 thousand in cash and 20,275 shares of common stock.  Pursuant to the Plan, during the year ended December 31, 2013, the Recovery Trustee settled an additional 59 claims with an aggregate face amount of $26.9 million for approximately $5.4 million in cash and 208,460 shares of common stock.

As of December 31, 2013, it is estimated that a total of 28 claims totaling approximately $40.2 million remain to be resolved by the Recovery Trustee. The largest remaining proof of claim was filed by the US 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 the Predecessor company 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, 2013 and 2012, we have reserved approximately $3.8 million and $8.7 million, respectively, representing the estimated value of claims remaining to be settled which are deemed probable and estimable at period end. A summary of claims is as follows (in thousands, except number of filed claims):

	Emergence-Date August 31, 2012				From Emergence-Date through December 31, 2012
											Remaining Filed
	Filed Claims				Settled Claims						Claims
								Consideration
	Count		Amount		Count	Amount		Cash		Stock	Count	Amount
U.S. Government Claims		3	$	22,364	—	$	—	$	—	—	3	$	22,364
Former Employee Claims		32		16,380	13		3,685		230	20	19		12,695
Macquarie Capital (USA) Inc.		1		8,672	—		—		—	—	1		8,672
Swann and BuzzardCreek    RoyaltyTrust		1		3,200	—		—		—	—	1		3,200
Other Various Claims*		75		23,114	12		2,915		29	—	63		20,199
Total		112	$	73,730	25	$	6,600	$	259	20	87	$	67,130

	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.

Capital Leases

Within our refining, distribution and marketing 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):

2014	$	382
2015		382
2016		382
2017		382
2018		420
Thereafter		420
Total minimum lease payments		2,368
Less amount representing interest		634
Total minimum rental payments	$	1,734

Operating Leases

Within our refining, distribution and marketing 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):

2014	$	22,724
2015		13,277
2016		12,362
2017		10,375
2018		9,244
Thereafter		25,614
Total minimum rental payments	$	93,596

Rent expense for the year ended December 31, 2013 and for the period from September 1, 2012 through December 31, 2012 was approximately $6.2 million  and $61 thousand, respectively.

Major Customers

For the year ended December 31, 2013, no individual customer accounted for more than 10% of our consolidated revenue. For the period September 1, 2012 to December 31, 2012, we had one customer that accounted for 96% of our total oil and natural gas sales. During the period from January 1, 2012 to August 31, 2012, our Predecessor had two customers that accounted individually for 59% and 24%, respectively, of its total oil and natural gas sales. 

Other

On April 22, 2013, Texadian entered into a terminaling and storage agreement whereby the operator will provide Texadian with storage facilities, access to a marine terminal and pipelines, and railcar offloading services. The initial term of the agreement is for a period of four years and Texadian’s minimum commitment during the initial term is approximately $28 million.

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Reorganization Under Chapter 11, Fresh-Start Reporting and the Effects of the Plan (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2012
Preconfirmation, Current assets
Cash and cash equivalents			$ 1,954
Trust assets			0
Restricted cash			0
Trade accounts receivable, net			3,708
Prepaid assets			4,777
Prepaid reorganization costs			1,326
Total current assets			11,765
Preconfirmation, Oil and gas properties
Unproved			84
Proved			759,755
Land			4,000
Other			73,021
Total property and equipment			836,860
Less accumulated depreciation and depletion			(642,172)
Property and equipment, net			194,688
Preconfirmation, Long-term assets:
Investments in unconsolidated affiliates			3,629
Other long-term assets			307
Total long-term assets			3,936
Total assets			210,389
Preconfirmation, Liabilities not subject to compromise
Debtor in possession financing			56,535
Accounts payable and other accrued liabilities			4,897
Other accrued liabilities			9,224
Accrued reorganization and trustee expense			70,656
Preconfirmation, Liabilities subject to compromise
3 3/4% Senior notes			115,000
7% Senior convertible notes			150,000
Accounts payable and other accrued liabilities			17,203
Total current liabilities			352,859
Preconfirmation, Liabilities not subject to compromise
Long - term debt			0
Derivative liabilities			0
Asset retirement obligations	3,172	512	476
Total liabilities			357,273
Preconfirmation, Stockholders’ equity
Common stock			288
Additional paid-in capital			1,643,285
Retained earnings (accumulated deficit)			(1,790,457)
Total stockholders' equity (deficit)			(146,884)
Total liabilities and equity (deficit)			210,389
Fresh Start Reporting Adjustments, Current assets
Trade accounts receivable, net			(1,981)	[1]
Prepaid assets			(4,777)	[1]
Prepaid reorganization costs			(1,326)	[1]
Fresh Start Reporting Adjustments, Oil and gas properties
Unproved			(84)	[1]
Proved			(14,776)	[1]
Other			(21,289)	[1]
Less accumulated depreciation and depletion			34,569	[1]
Fresh Start Reporting Adjustments, Long-term assets:
Investments in unconsolidated affiliates			(3,629)	[1]
Other long-term assets			(253)	[1]
Fresh Start Reporting Adjustments, Liabilities subject to compromise
Accounts payable and other accrued liabilities			(1,981)	[1]
Fresh Start Reporting Adjustments, Stockholders' equity
Common stock			(288)	[2]
Additional paid-in capital			288	[2]
Retained earnings (accumulated deficit)			(14,765)	[1]
Postconfirmation, Current assets
Cash and cash equivalents			4,882
Trust assets			3,446
Restricted cash			20,359
Trade accounts receivable, net			0
Prepaid assets			0
Prepaid reorganization costs			0
Total current assets			28,687
Postconfirmation, Oil and gas properties
Unproved			0
Proved			4,587
Land			0
Other			4,239
Total property and equipment			8,826
Less accumulated depreciation and depletion			0
Property and equipment, net			8,826
Postconfirmation, Long-term assets:
Investments in unconsolidated affiliates			105,344
Other long-term assets			54
Total long-term assets			105,398
Total assets			142,911
Postconfirmation, Liabilities not subject to compromise
Debtor in possession financing			0
Accounts payable and other accrued liabilities			4,897
Other accrued liabilities			2,640
Accrued reorganization and trustee expense			7,537
Postconfirmation, Liabilities subject to compromise
3 3/4% Senior notes			0
7% Senior convertible notes			0
Accounts payable and other accrued liabilities			12,336
Total current liabilities			19,873
Postconfirmation, Liabilities not subject to compromise
Long - term debt			6,335
Derivative liabilities			6,665
Asset retirement obligations			476
Total liabilities			33,349
Postconfirmation, Stockholders' equity
Common stock			1,477
Additional paid-in capital			108,085
Retained earnings (accumulated deficit)			0
Total stockholders' equity (deficit)			109,562
Total liabilities and equity (deficit)			142,911
Reflects Adjustments To Remaining Assets [Member]
Fresh Start Reporting Adjustments, Liabilities subject to compromise
Accounts payable and other accrued liabilities			3,200	[1]
Reflects Elimination of Predecessor Accumulated Deficit [Member]
Fresh Start Reporting Adjustments, Stockholders' equity
Additional paid-in capital			(1,636,890)	[3]
Retained earnings (accumulated deficit)			1,636,890	[3]
Plan of Reorganization Adjustments [Member]
Preconfirmation, Current assets
Cash and cash equivalents			74,167	[4]
Trust assets			3,446	[5]
Restricted cash			20,359	[6]
Trade accounts receivable, net			(1,727)	[4]
Preconfirmation, Oil and gas properties
Proved			(740,392)	[4]
Land			(4,000)	[4]
Other			(47,493)	[4]
Less accumulated depreciation and depletion			607,603	[4]
Preconfirmation, Long-term assets:
Investments in unconsolidated affiliates			105,344	[4]
Preconfirmation, Liabilities not subject to compromise
Debtor in possession financing			(56,535)	[7]
Other accrued liabilities			(2,685)	[8]
Preconfirmation, Liabilities subject to compromise
3 3/4% Senior notes			(115,000)	[8]
7% Senior convertible notes			(150,000)	[8]
Accounts payable and other accrued liabilities			(2,560)	[4]
Preconfirmation, Liabilities not subject to compromise
Long - term debt			6,335	[7]
Derivative liabilities			6,665	[7]
Asset retirement obligations			(3,938)	[4]
Preconfirmation, Stockholders’ equity
Common stock			1,457	[8]
Additional paid-in capital			100,084	[8]
Retained earnings (accumulated deficit)			166,144	[8]
Plan of Reorganization Adjustments [Member] | Reflects The Successor Drawing [Member]
Preconfirmation, Current assets
Cash and cash equivalents			(45,035)	[7]
Preconfirmation, Liabilities not subject to compromise
Other accrued liabilities			(1,500)	[7]
Plan of Reorganization Adjustments [Member] | Reflects Settlement of Other Claims [Member]
Preconfirmation, Current assets
Cash and cash equivalents			(24,204)	[6]
Preconfirmation, Liabilities not subject to compromise
Other accrued liabilities			(3,845)	[6]
Preconfirmation, Liabilities subject to compromise
Accounts payable and other accrued liabilities			(3,526)	[6]
Preconfirmation, Stockholders’ equity
Common stock			20	[6]
Additional paid-in capital			1,318	[6]
Retained earnings (accumulated deficit)			2,188	[6]
Plan of Reorganization Adjustments [Member] | Reflects Funding of The Recovery Trusts [Member]
Preconfirmation, Current assets
Cash and cash equivalents			(2,000)	[5]
Preconfirmation, Liabilities not subject to compromise
Other accrued liabilities			$ 1,446	[5]

[1] Reflects adjustments to remaining assets due to fresh start accounting. On the Emergence Date, we adjusted the carrying value of our remaining assets to their estimated fair values. As a result of these adjustments, we recorded a loss for changes in asset fair values due to fresh start accounting adjustments within Reorganization items of approximately $14.8 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.

[2] Reflects cancellation of Predecessor common stock.

[3] Reflects elimination of Predecessor accumulated deficit.

[4] Reflects contribution of certain of our oil and gas assets and related prepaid expenses and asset retirement obligations to Piceance Energy in exchange for cash and a 33.34% interest in Piceance Energy.

[5] Reflects funding of the Recovery Trusts (see Note 9).

[6] Reflects settlement of other claims with common stock of Successor and cash. On the Emergence Date, we issued 191,973 shares of our common stock to various creditors. We estimated the fair value of our common stock to be $7.0 on the Emergence Date. Accordingly, we recorded a gain on settlement of liabilities within Reorganization items of approximately $2.2 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.

[7] Reflects the Successor drawing $13 million under the Loan Agreement (see Note 6) to repay amounts outstanding under the DIP Credit Facility (see Note 6) with those proceeds and cash from contribution of assets to Piceance Energy.

[8] Reflects extinguishment of secured debt in exchange for common stock of the Successor. On the Emergence Date, we issued 14,573,608 shares of our common stock and warrants to acquire 959,213 shares of our common stock to the holders of our secured debt or their affiliates. We estimated the fair value of our common stock to be $7.0 on the Emergence Date. Accordingly, we recorded a gain on the settlement of secured debt within Reorganization items of approximately $166.1 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.