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, 2012

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 incorporation or organization)	(I.R.S. Employer Identification No.)

1301 McKinney, Suite 2025 Houston, Texas	77010
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 969-3293

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.  x

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 $2,860,000, based on the closing price of the Common Stock on the OTC Bulletin Board of $0.10 per share as of June 29, 2012. As of March 25, 2013, 150,080,405 shares of registrant’s Common Stock, $0.01 par value, were issued and outstanding.

TABLE OF CONTENTS

	PAGE
PART I
Item 1. BUSINESS		3
Item 1A. RISK FACTORS		14
Item 1B. UNRESOLVED STAFF COMMENTS		25
Item 2. PROPERTIES		25
Item 3. LEGAL PROCEEDINGS		30
Item 4. MINE SAFETY DISCLOSURES		30
PART II
Item  5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		30
Item 6. SELECTED FINANCIAL DATA		31
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		31
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		47
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		47
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		47
Item 9A. CONTROLS AND PROCEDURES		48
Item 9B. OTHER INFORMATION		48
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		49
Item 11. EXECUTIVE COMPENSATION		52
Item  12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		55
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		57
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES		58
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES		60

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform our existing and potential security holders generally of some of the risks, trends and uncertainties that can affect us and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about us. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “propose,” “potential,” “predict,” “forecast,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Except for statements of historical or present facts, all other statements contained in this Annual Report on Form 10-K are forward-looking statements.

Among those risks, trends and uncertainties are:

• the continued availability of our net operating loss tax carryforwards;

• our dependence on the results of Piceance Energy;

• our ability to control activities on properties we do not operate;

• inadequate liquidity;

• identifying future acquisitions and our diligence of any acquired properties;

• our level of indebtedness;

• our ability to generate cash flow;

• the volatility of natural gas and oil prices, including the effect of local or regional factors;

• instability in the global financial system;

• uncertainties in the estimation of proved reserves and in the projection of future rates of production;

• our ability to replace production;

• the success of our exploration and development efforts;

• declines in the values of our natural gas and oil properties resulting in writedowns;

• timing, amount, and marketability of production;

• third party curtailment, or processing plant or pipeline capacity constraints beyond our control;

• the strength and financial resources of our competitors;

• seasonal weather conditions;

• operating hazards that result in losses;

• uninsured or underinsured operating activities;

• legal and/or regulatory compliance requirements;

• credit risk of our contract counterparties;

• effectiveness of our disclosure controls and procedures and our internal controls over financial reporting;

• our ability to develop and grow our marketing, transportation, distribution and logistics business;

• the illiquidity and price volatility of our common stock;

• the concentrated ownership of our common stock;

• the success of Texadian’s risk management strategies;

• compliance with laws and regulations relating to Texadian’s business; and

• commodity price risk for the business of Texadian.

Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.

1

You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other “forward-looking” information within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). You should be aware that the occurrence of any of the events described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and elsewhere in this Annual Report on Form 10-K could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common stock could decline, and you could lose all or part of your investment.

All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements above and other cautionary statements included in this Annual Report on Form 10-K. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

We caution you not to place undue reliance on these forward-looking statements. We urge you to carefully review and consider the disclosures made in this Annual Report on Form 10-K and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risk factors that may affect our business.

The terms “Par,” “Company,” “we,” “our,” and “us” refer to Par Petroleum Corporation (and for periods prior to the reorganization described herein, Delta Petroleum Corporation) and its consolidated subsidiaries unless the context suggests otherwise.

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PART I

Item 1. Business

General

We are an independent natural gas and oil company based in Houston, Texas. Our primary asset is a 33.34% non-operated equity interest in Piceance Energy, LLC (“Piceance Energy”), as described in more detail below. We are the successor entity to Delta Petroleum Corporation (“Delta” or “Predecessor”) following its emergence from bankruptcy. On emergence, Delta changed its name to Par Petroleum Corporation (“Par” or “Successor”). In addition to our interest in Piceance Energy, we own non-operated working interests in offshore California, Colorado and New Mexico. Our total estimated proved reserves as of December 31, 2012, which includes our share of the estimated proved reserves of Piceance Energy, were 167.9 Bcfe, consisting of 123.1 Bcf of natural gas, 6.3 MMBbls of NGLs and 1.1 MMBbls of oil. The pre-tax present value, discounted at 10%, of the estimated future net revenues based on average prices during 2012 (“PV-10”) of our estimated proved reserves at December 31, 2012 was approximately $80.0 million. At December 31, 2012, our standardized measure of discounted cash flows, which includes the estimated impact of future income taxes, totaled approximately $80.0 million (See “— Natural Gas and Oil Operations — Reconciliation of PV-10 to Standardized Measure” for a reconciliation of PV-10 to our standardized measure of discounted cash flow).

On December 31, 2012, we acquired Texadian Energy, Inc. (formerly known as SEACOR Energy Inc. (“Texadian”)) for approximately $14.0 million plus estimated working capital at closing. Texadian operates a crude oil sourcing, marketing, transportation and distribution business with significant logistics capability in historical pipeline shipping status, a rail car fleet, and tow and barge chartering. As a result of this acquisition, our business for 2013 and future years will also include commodities marketing and logistics relating to the purchase, storage, transportation and sale of energy and related products.

Our principal executive office is located at 1301 McKinney, Suite 2025, Houston, Texas 77010, and our telephone number is (713) 969-3293.

Bankruptcy and Plan of Reorganization

Background and Plan Approval

On December 16, 2011, Delta Petroleum Corporation (“Delta”) and its subsidiaries Amber Resources Company of Colorado, DPCA, LLC, Delta Exploration Company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc. and Castle Texas Production Limited Partnership 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”). On January 6, 2012, Castle Exploration Company, Inc., a subsidiary of Delta Pipeline, LLC, also filed a voluntary petition under Chapter 11 in the Bankruptcy Court. Delta and its subsidiaries included in the bankruptcy petitions are collectively referred to as the “Debtors.”

On December 27, 2011, the Debtors filed a motion requesting an order to approve matters relating to a proposed sale of Delta’s assets, including bidding procedures, establishment of a sale auction date and establishment of a sale hearing date. On January 11, 2012, the Bankruptcy Court issued an order approving these matters. On March 20, 2012, Delta announced that it was seeking court approval to amend the bidding procedures for its upcoming auction to allow bids relating to potential plans of reorganization as well as asset sales. On March 22, 2012, the Bankruptcy Court approved the revised procedures.

Following the auction, 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 connection with the Plan, Delta entered into a non-binding term sheet describing a transaction by which Laramie and Delta intended to form a new joint venture called Piceance Energy LLC (“Piceance Energy”). On June 4, 2012, Delta entered into a Contribution Agreement (the “Contribution Agreement”) with Piceance Energy and Laramie to effect the transactions contemplated by the term sheet.

On June 4, 2012, the Debtors filed a disclosure statement relating to the Plan. The Plan was confirmed on August 16, 2012 and 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.

On the Emergence Date, Delta also amended and restated its certificate of incorporation and bylaws. 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. Under the amended and restated bylaws, the Company’s board of directors has five members, each of whom was appointed by our stockholders pursuant to a Stockholders’ Agreement entered into on the Emergence Date.

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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 “LLC Agreement”). The business of Piceance Energy is to own the natural gas and oil, surface real estate, and related assets formerly owned by Laramie and the Company in Garfield and Mesa Counties, Colorado, or other assets subsequently acquired by Piceance Energy, and to operate such assets. Pursuant to the LLC Agreement, Piceance is managed by Laramie, which controls its day-to-day operations, subject to the supervision of a six-person board, four (4) of which were appointed by Laramie and two (2) of which were appointed by Par Piceance Energy Equity. Certain major decisions require the unanimous consent of the board. The LLC Agreement provides that the sole manager, which is initially Laramie, 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, if approved by a majority of the board. If any member does not fund their share of the capital call, their interest may be reduced or diluted to the extent of the shortfall. The 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 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.

In addition, Laramie and Piceance Energy entered into a Management Services Agreement pursuant to which Laramie agreed to provide certain services to Piceance Energy for a fee of $650,000 per month.

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, 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 $1.0 million each pursuant to the Plan.

On September 19, 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. Further distributions are not anticipated from the Wapiti Trust and the Wapiti Trust is anticipated to be 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 Executive Officer is the 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 for each of the Recovery Trusts, subject to the terms of the respective trust agreements 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 March 19, 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, 106 claims totaling approximately $73.7 million had been filed in the bankruptcy. 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 $258,905 in cash and 202,753 shares of stock. Subsequent to year end and up to March 25, 2013, the Recovery Trustee settled an additional 25 claims with an aggregate face amount of $12.3 million for approximately $676,092 in cash and 1,469,575 shares of stock.

4

As of March 25, 2013, it is estimated that a total of 56 claims totaling $54.8 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. Par believes 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. In addition, litigation and/or settlement efforts are ongoing with Macquarie Capital (USA) Inc., Swann and Buzzard Creek Royalty Trust, as well as other claim holders.

The settlement of claims is subject to ongoing litigation and we are unable to predict with certainty how many shares of our common stock will be required to satisfy all claims. Pursuant to the Plan, allowed claims are settled at a ratio of 544 shares per $1,000 of claim. At December 31, 2012, we have a reserve of approximately $8.7 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at year end. A summary of claims is as follows:

	Emergence-Date August 31, 2012				Year-ended December 31, 2012
	Filed Claims				Settled Claims								Remaining Filed Claims
									Consideration
	Count		Amount		Count		Amount		Cash		Stock		Count		Amount
U.S. Government Claims		3	$	22,364,000		—	$	—	$	—		—		3	$	22,364,000
Former Employee Claims		32		16,379,849		13		3,685,253		229,478		202,231		19		12,694,596
Macquarie Capital (USA) Inc.		1		8,671,865		—		—		—		—		1		8,671,865
Swann And Buzzard Creek Royalty Trust		1		3,200,000		—		—		—		—		1		3,200,000
Other Various Claims*		69		23,120,396		12		2,914,859		29,427		522		57		20,205,537
Total		106	$	73,736,110		25	$	6,600,112	$	258,905		202,753		81	$	67,135,998

	Subsequent to Year-ended December 31, 2012 through March 19, 2013
	Settled Claims								Remaining Filed Claims
					Consideration
	Count		Amount		Cash		Stock		Count		Amount
U.S. Government Claims		—	$	—	$	—		—		3	$	22,364,000
Former Employee Claims		12		11,750,904		278,338		1,361,452		7		943,692
Macquarie Capital (USA) Inc.		—		—		—		—		1		8,671,865
Swann And Buzzard Creek Royalty Trust		—		—		—		—		1		3,200,000
Other Various Claims*		13		581,607		397,754		108,123		44		19,623,930
Total		25	$	12,332,511	$	676,092		1,469,575		56	$	54,803,487

* Includes reserve for contingent/unliquidated claims in the amount of $10 million.

Laramie and Piceance Energy

Laramie is a Denver-based company primarily focused on finding and developing natural gas reserves from unconventional gas reservoirs within the Rocky Mountain region. Its predecessor company, Laramie Energy, LLC (“Laramie I”), sold all of its natural gas and oil assets in May 2007 to Plains Exploration & Production Company, Inc. Laramie was formed in June 2007 by Laramie I executives and former employees and by affiliates of the private equity investors in Laramie I. Laramie is backed by equity capital commitments funded by Laramie’s management team, EnCap Investments, Avista Capital, and DLJ Merchant Banking Partners (an affiliate of Credit Suisse Securities).

All of the assets contributed to Piceance Energy are located within Garfield and Mesa Counties, Colorado and are within a 10-mile radius in the Piceance Basin geologic formation. All of the natural gas and oil reserves contributed to Piceance Energy produce from the same geologic formations, the Mesaverde and Mancos Formations, and some of the contributed acreage is contiguous.

As of December 31, 2012, the estimated proved reserves of Piceance Energy are the following (unaudited):

	Natural Gas (MMcf)		Oil (MBbls)		NGLs (MBbls)		Total (MMcfe)
Proved Developed		146,012		711		6,756		190,814
Proved Undeveloped		221,863		1,780		12,274		306,187
Total Proved		367,875		2,491		19,030		497,001

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Natural Gas and Oil Operations

Natural Gas and Oil Reserves

The following table presents the estimated proved reserves that we own directly and indirectly through Piceance Energy as of December 31, 2012:

	Natural Gas (MMcf)		Oil (MBbl)		NGLs (MBbLs)		Total (MMcfe)  (2)
Company:
Proved Developed		158		286		—		1,875
Proved Undeveloped		288		—		—		288
Total Proved Reserves - Company		446		286		—		2,163
Company Share of Piceance Energy:
Proved Developed		48,680		237		2,253		63,617
Proved Undeveloped		73,970		594		4,092		102,083
Total Proved Reserves- Piceance Energy		122,650		831		6,345		165,700
Total Combined Proved Reserves		123,096		1,117		6,345		167,863

	Proved Developed Producing		Proved Developed Non-producing		Proved Undeveloped		Total(1)
	(M$)		(M$)		(M$)		(M$)
Company:
Estimated pre-tax future net cash flows	$	9,277	$	—	$	252	$	9,529
Standardized measure of discounted future net cash flows	$	7,790	$	—	$	220	$	8,010
Company Share of Piceance Energy:
Estimated pre-tax future net cash flows	$	62,165	$	39,150	$	114,060	$	215,375
Standardized measure of discounted future net cash flows	$	39,265	$	13,039	$	19,655	$	71,959
Total
Estimated pre-tax future net cash flows	$	71,442	$	39,150	$	114,312	$	224,904
Standardized measure of discounted future net cash flows	$	47,055	$	13,039	$	19,875	$	79,969

⁽¹⁾ Based on historical first of month twelve month average posted price of $91.21 per Bbl for WTI oil and a spot price of $2.56 per MMBtu for CIG natural gas, in each case before adjusting for differentials, contractual deducts and similar factors. The price used for natural gas liquids is based on differentials using the WTI oil price and is $34.66 per barrel.

⁽²⁾  MMcfe is computed converting to gas using a ratio of 6 Mcf to 1 barrel of oil or NGL.

Reconciliation of PV-10 to Standardized Measure

PV-10 is the estimated present value of the future net revenues from our 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 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. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. 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, 2012 (in thousands):

	Company		Company Share of Piceance Energy		Total
PV-10	$	8,010	$	71,959	$	79,969
Present value of future income taxes discounted at 10%		—		—		—
Standardized measure of discounted future net cash flows	$	8,010	$	71,959	$	79,969

Natural Gas and Oil Reserves

Our natural gas and oil operations prior to the Emergence Date were comprised primarily of production of natural gas and oil, drilling exploratory and development wells and related operations and acquiring and selling natural gas and oil properties. We currently own 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 operations primarily consists 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. We have no material patents, licenses, franchises or concessions that we consider significant to our natural gas and oil operations. The nature of our natural gas and oil business is such that it is not seasonal in any material respect. In addition, we do not engage in any research and development activities and we do not maintain or require a substantial amount of products, customer orders or inventory related to natural gas and oil operations. Our natural gas and oil operations are not subject to renegotiations of profits or termination of contracts at the election of the federal government.

For more on our natural gas and oil operations, see “Item 2. Properties.”

Markets and Distribution

The principal products produced by us are natural gas and oil. 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 as discussed below. 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.

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Our ability to market natural gas and oil from our wells depends upon numerous factors beyond our control, including the extent of domestic production and imports of natural gas and oil; the proximity of the natural gas production to pipelines; the availability of capacity in such pipelines; the demand for natural gas and oil by utilities and other end users; the availability of alternative fuel sources; the effects of inclement weather; state and federal regulation of natural gas and oil production; and federal regulation of gas sold or transported in interstate commerce.

Competition

We encounter strong competition from major oil companies and independent operators in acquiring properties and leases for the exploration for, and the development and production of, natural gas and crude oil. Competition is particularly intense with respect to the acquisition of desirable undeveloped natural gas and oil leases. The principal competitive factors in the acquisition of undeveloped natural gas and oil leases include the availability and quality of staff and data necessary to identify, investigate and purchase such leases, and the financial resources necessary to acquire and develop such leases. Many of our competitors have substantially greater financial resources and more fully developed staffs and facilities than ours. In addition, the producing, processing and marketing of natural gas and oil are affected by a number of factors which are beyond our control, the effect of which cannot be accurately predicted. See “Item 1A. Risk Factors.”

Major Customers

For the period September 1, 2012 to December 31, 2012, we had one customer that accounted for 96% of the Successor’s total oil and natural gas sales. During the period from January 1, 2012 to August 31, 2012 we had two customers that accounted individually for 59% and 24%, respectively, of the Predecessor’s total oil and natural gas sales. For the year ended December 31, 2011, two customers accounted individually for 56% and 19%, respectively, of the Predecessor’s total oil and gas sales. Although a substantial portion of production is purchased by these major customers, we do not believe that the loss of a customer would have a material adverse effect on our business as other customers or markets would be accessible to us.

Commodity Marketing and Logistics Operations

Texadian operates an integrated business involved in sourcing, marketing, transportation and distribution of energy commodities. The principal commodity currently involved is crude oil. We acquired this part of our business on December 31, 2012, as described above under “– General.” The following description is based on the business of Texadian as conducted prior to our acquisition, which is how we expect to continue to operate in 2013.

Products and Services

Texadian is primarily focused on the domestic merchandising and transportation of crude oil, and uses a variety of transportation modes, which are generally leased, to transport its products, including trucks, railcars, river barges, and pipelines.

Markets

Texadian’s activities are dependent upon factors that Texadian cannot control, including macro and micro economic supply and demand factors, governmental intervention or mandates, weather patterns, and the price and availability of substitute products. Texadian purchases and resells crude oil primarily from the western United States and Canada to customers in the United States coastal regions and delivers the crude oil via pipeline and barge.

Competition

The commodity marketing and logistics business is highly competitive. Major competitors include other marketers, traders, the major integrated oil companies, midstream energy providers, and other product suppliers.

Customers and Contractual Arrangements

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

In 2012, two customers of Texadian, Motiva and Chevron, were responsible for 10% or more of consolidated operating revenues. The ten largest customers of Texadian accounted for approximately 95% of its operating revenues in 2012. While this concentration has the ability to negatively impact revenues going forward, management does not anticipate a material adverse effect in our financial position, results of operations or cash flows as the absolute price levels for crude oil normally do not bear a relationship to gross profit. In addition, the customers are subject to netting arrangements which allow us to offset payable activities and serve to mitigate credit exposure.

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Contract Drilling Operations

Our Predecessor owned an interest in DHS Drilling Company (“DHS”), a contract drilling company that is headquartered in Casper, Wyoming. DHS was a consolidated subsidiary of Delta. Subsequent to our 2010 year end, the Board of Directors of DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of the company or substantially all of its assets. During the fourth quarter of 2011, Delta sold its entire interest in DHS; DHS is reflected as a discontinued operation for all periods presented in our consolidated financial statements.

DHS also owned 100% of Chapman Trucking which provided moving services for DHS and for third party drilling rigs. DHS sold Chapman during 2011.

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 Bureau of Ocean Energy Management (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.

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.

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

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

Federal Leases

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

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

To cover the various obligations of lessees on the Outer Continental Shelf (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.

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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.

In particular, the Colorado Oil and Gas Conservation Commission (the “COGCC”) is expected to approve and implement new setback rules for oil and gas wells and production facilities located in close proximity to occupied buildings. If the new setback rules are approved, the current COGCC setback distances of 150 feet in rural areas and 350 feet in high density urban areas will be increased 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 would 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 would also require advance notice to surface owners, the owners of occupied buildings and local governments prior to the filing of an Application for Permit to Drill or Oil and Gas Location Assessment, as well as expanded outreach and communication efforts by an operator.

The COGCC also approved two new rules making Colorado the first state to require sampling of 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, between six and 12 months after completion, and between five and six years after completion. The revised rule for the GWA requires operators to sample only one water well per quarter governmental section before drilling and between six to 12 months after completion.

Legislative Proposals

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

Impact of Dodd-Frank Act Derivatives Regulation

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which was passed by Congress and signed into law in July 2010, contains significant derivatives regulation, including requirements that certain transactions be cleared on exchanges and that collateral (commonly referred to as “margin”) be posted for such transactions. The Dodd-Frank Act provides for a

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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, although the CFTC has stated it will appeal the District Court decision.

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.

Environmental Regulation

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.

Our activities with respect to exploration and production of oil and natural gas, 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 (the “USEPA”). Such regulation can increase the cost of planning, designing, installation and operation of 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. The California Environmental Quality Act (the “CEQA”) is a statute that requires consideration of the environmental impacts of proposed actions that may have a significant effect on the environment. CEQA requires the responsible governmental agency to prepare an environmental impact report that is made available for public comment. The responsible agency also is required to consider mitigation measures. The party requesting agency action bears the expense of the report. At a minimum, the CEQA process delays and adds expense to the process of obtaining new leases, permits and lease renewals.

Solid and Hazardous Waste

We generate wastes, including hazardous wastes, which are subject to regulation under the federal Resource Conservation and Recovery Act (“RCRA”) and state statutes. The USEPA has limited the disposal options for certain hazardous wastes, and state regulation of the handling and disposal of oil and gas exploration and production wastes and other solid wastes is becoming more stringent. Furthermore, it is possible that certain wastes generated by our oil and gas 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.

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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 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 oil and gas 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 plugging 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 owner and operator of a site and persons that disposed or arranged for the disposal of hazardous substances at a site. CERCLA also authorizes the USEPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible persons the costs of such action. State statutes impose similar liability.

Under CERCLA, the term “hazardous substance” does not include “petroleum, including crude oil or any fraction thereof,” unless specifically listed or designated and the term does not include natural gas, NGLs, liquefied natural gas, or synthetic gas usable for fuel. While this “petroleum exclusion” lessens the significance of CERCLA to our operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance” in the course of our ordinary 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 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 regulations 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. A 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 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 by 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.

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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 COGCC approved rules that require sampling of groundwater for hydrocarbons and other indicator compounds both before and after drilling. Sampling results are to be reported to the COGCC, which maintains a water quality database online and available to the public.

Hydraulic Fracturing

Our 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 USEPA has commissioned a study to identify potential risks associated with hydraulic fracturing. The USEPA published a progress report on this study in December 2012 and a final draft report will be delivered in 2014. Additionally, the BLM proposed to regulate the use of hydraulic fracturing on federal and tribal lands, but following extensive public comment on the proposals, announced it would issue an improved proposal before finalizing new rules. The revised proposal is expected to address 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. Depending on the results of the USEPA 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.

Air Emissions

Our 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.

The USEPA 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 2012, 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.

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

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response the USEPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. The USEPA has also promulgated rules requiring large sources to report their GHG emissions. Sources subject to these reporting requirements 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. [We are not subject to GHG reporting requirements. In addition, the USEPA promulgated rules that significantly increase the GHG emission threshold that would identify major stationary sources of GHG subject to CAA permitting programs. As currently written and based on current Company operations, we are not subject to federal GHG permitting requirements. 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. Further, apart from these developments, state 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.

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.

The California Coastal Act regulates the conservation and development of California’s coastal resources. The California Coastal Commission (the “Coastal Commission”) works with local governments to make permit decisions for new developments in certain coastal areas and reviews local coastal programs, such as land-use restrictions. The Coastal Commission also works with the California Office of Spill Prevention and Response to protect against and respond to coastal oil spills. The Coastal Commission has direct regulatory authority over offshore oil and natural gas development within the state’s three mile jurisdiction and has authority, through the CZMA, over federally permitted projects that affect the state’s coastal zone resources. We conduct activities that may be subject to the California Coastal Act and the jurisdiction of the Coastal Commission.

Employees

At December 31, 2012, prior to the closing of the Texadian acquisition, we had no full-time employees. Executive, accounting, landmen, attorneys and others necessary for our operations are retained on a contract or fee basis as their services are required. For more on our contract for the services of our executive officers, see “Part III. Item 11. Executive Compensation – Compensation Discussion and Analysis.”

Item 1A. Risk Factors.

You should carefully read and consider the risks described below before deciding to invest in our securities. The occurrence of any such risks may materially harm our business, financial condition, results of operations or cash flows. In any such case, the trading price of our common stock and other securities could decline, and you could lose all or part of your investment. When determining whether to invest in our securities, you should also refer to the other information contained in this Annual Report on Form 10-K, including our consolidated financial statements and the related notes, and in our other filings with the Securities and Exchange Commission (the “SEC”).

Our primary asset is our non-operated interest in Piceance Energy and Piceance Energy will face substantially similar risk factors to those that face other natural gas exploration and production companies, including us, as described herein. All disclosures in this Annual Report on Form 10-K regarding operational risks facing us will also be operational risks faced by Piceance Energy.

Risks Related to our Natural Gas and Oil Business and Operations

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

As of December 31, 2012, we estimated that we had approximately $1.3 billion of net operating losses (“NOLs”). In order to utilize the NOLs, we must generate taxable income which can offset such carryforwards. The NOLs will expire if not used. The availability of NOLs to offset taxable income would be substantially reduced if we were to undergo an “ownership change” within the meaning of Section 382(g)(1) 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 a three year “testing period” by “5% stockholders.”

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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 force as long as the NOLs are available. 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.

We are dependent on the results of Piceance Energy.

Our principal asset is our 33.34% ownership interest in Piceance Energy. Our operating income will therefore depend heavily 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 (as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Piceance Energy—Piceance Energy Credit Facility”). In addition, Laramie 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. Piceance Energy also pays to Laramie a monthly fee of $650,000 to operate and manage its assets. This will further limit Piceance Energy’s ability to make distributions to us. Our results of operations could be adversely affected until we are able to receive distributions from Piceance Energy on a timely basis.

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.

Although we have representation on the board of managers of Piceance Energy, Piceance Energy is managed by Laramie, which controls its day-to-day operations. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities therefore will depend upon a number of factors outside of our control, including Laramie’s:

• 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 Laramie to act in ways that are in our best interest, our results of operations could be adversely affected.

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

Following the consummation of the Plan and our emergence from bankruptcy, our primary source of cash flow has been borrowings under the Loan Agreement (as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”). 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 the restrictions on Piceance Energy’s ability to distribute cash to us under the Piceance Energy Credit Facility, by our need to satisfy our obligations under our debt agreements including in particular the Compass Letter of Credit Facility and Tranche B Loan (each as described in “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”), which mature on December 26, 2013 and July 1, 2013, respectively, and by potential capital contributions to be made by us to Piceance Energy under the LLC Agreement. Our liquidity will be further constrained by the currently low level of natural gas prices, which reduces our cash flows from operations. 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, natural gas and oil prices, our credit ratings, interest rates, market perceptions of us or the natural gas and oil industry, 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.

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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, including acquisitions of natural gas and oil businesses and properties. 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 business. 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. The success of any acquisition of natural gas and oil properties will depend on a number of factors, including the ability to estimate accurately the recoverable volumes of reserves, rates of future production and future net revenues attainable from the reserves and to assess possible environmental liabilities. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our results of operations.

Due diligence of acquired natural gas and oil properties and businesses is often incomplete, which could harm our results of operations.

Even though we perform due diligence reviews (including a review of title and other records) of the natural gas and oil properties we seek to acquire that we believe is consistent with industry practices, these reviews are inherently incomplete. It is generally not feasible for us to perform an in-depth review of every individual property and all records involved in each acquisition. However, even an in-depth review of records and properties may not necessarily reveal existing or potential problems or permit us to become familiar enough with the properties to assess fully their deficiencies and potential. Even when problems are identified, we may assume certain environmental and other risks and liabilities in connection with the acquired businesses and properties. The discovery of any material liabilities associated with our acquisitions could harm our results of operations.

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 degree of leverage could have important consequences, including the following:

• it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, acquisitions and general corporate or other purposes;

• the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our obligations;

• borrowings may be at variable rates of interest, exposing us to the risk of increased interest rates;

• it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that have less debt; and

• we may from time to time be out of compliance with covenants under our debt agreements, which may allow the lenders to accelerate the related debt and foreclose on assets securing that debt.

In particular, the Compass Letter of Credit Facility and Tranche B Loan mature on December 26 and July 1, 2013, respectively. Our obligation to repay this indebtedness may 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 properties 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, 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.

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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 (including in particular the Compass Letter of Credit Facility and the Tranche B Loan which mature on December 26, 2013 and July 1, 2013, respectively) will depend on distributions from Piceance Energy, borrowings under our debt agreements and our ability to generate sufficient cash flow from operations in the future. 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 prices that we receive for our natural gas and oil production.

We cannot assure you that our business will generate sufficient cash flow from operations, that Piceance Energy 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 (including in particular the Compass Letter of Credit Facility and Tranche B Loan which mature on December 26, 2013 and July 1, 2013, respectively) 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.

Natural gas and oil prices are volatile. Lower prices have adversely affected our financial position, financial results, cash flows, access to capital and ability to grow.

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for the natural gas and oil we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.

Historically, the markets for natural gas and oil have been volatile and they are likely to continue to be volatile. Wide fluctuations in natural gas and oil prices may result from relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and other factors that are beyond our control, including:

• worldwide and domestic supplies of natural gas and oil;

• weather conditions;

• the level of consumer demand;

• the price and availability of alternative fuels;

• the proximity and capacity of natural gas pipelines and other transportation facilities;

• the price and level of foreign imports;

• domestic and foreign governmental regulations and taxes;

• the nature and extent of regulation relating to carbon and other GHG emissions;

• the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• political instability or armed conflict in oil-producing regions; and

• overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas and oil price movements. Declines in natural gas and oil prices not only reduce revenue, but also reduce the amount of natural gas and oil that we can produce economically and, as a result, have had, and could in the future have, a material adverse effect on our financial condition, results of operations, cash flows and reserves. Further, oil and natural gas prices do not move in tandem. Because approximately 73% of our reserves, and 74% of Piceance Energy’s reserves, at December 31, 2012 were natural gas reserves, we are more affected by movements in natural gas prices. Natural gas prices have fallen to historic lows in recent periods.

To attempt to reduce our price risk, we may enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in natural gas or oil prices. Any substantial or extended decline in the prices of or demand for natural gas or oil would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

The current financial environment may have impacts on our business and financial condition that we cannot predict.

The continued instability in the global financial system and related limitation on availability of credit may continue to have an impact on our business and our financial condition, and we may continue to face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets in the future when we would like, or need, to raise capital could be restricted as a result. The difficult financial environment may also limit the number of prospects for potential joint venture, asset monetization or other capital raising transactions that we may pursue in the future or reduce the values we are able to realize in those transactions,

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making these transactions uneconomic or difficult to consummate. The economic situation could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements, if any, to be ineffective if our counterparties are unable to perform their obligations. Additionally, the current economic situation could lead to reduced demand for natural gas and oil, or lower prices for natural gas and oil, or both, which would have a negative impact on our revenues.

Information concerning our 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.

The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves as of December 31, 2012 included in our periodic reports filed with the SEC were prepared by our 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.

We may not be able to replace production with new reserves.

Our reserves will decline as they are produced unless we acquire new properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves that are economically feasible and developing existing proved reserves, which is in turn dependent on, among other things, the availability of capital to fund such acquisition and development activity. A failure to acquire or develop new reserves would have a material adverse effect on our business and results of operations.

Exploration and development drilling may not result in commercially productive reserves.

We may not always encounter commercially producing reservoirs through our drilling operations, new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The seismic data and other technologies we may use would not allow us to know conclusively prior to drilling a well that natural gas or oil is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

• increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment;

• unexpected drilling conditions;

• title problems;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions; and

• compliance with environmental and other governmental requirements.

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If natural gas or oil prices decrease or exploration and development efforts are unsuccessful, we may be required to take further writedowns.

We have been required in the past to take writedowns of the carrying value of our natural gas and oil properties and other assets and may be required to do so in the future, which would reduce our earnings and there is a risk that we will be required to take additional writedowns. A writedown could occur when natural gas and oil prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration and development results.

We account for our natural gas and oil exploration and development activities utilizing the successful efforts method of accounting. Under this 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. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. If the carrying amount of our natural gas and oil properties exceeds the estimated undiscounted future net cash flows, we will adjust the carrying amount of the natural gas and oil properties to their estimated fair value.

We review our natural gas and oil properties for impairment quarterly or whenever events and circumstances indicate that the carrying value may not be recoverable. Once incurred, a writedown of natural gas and oil properties is not reversible at a later date even if natural gas or oil prices increase. Given the complexities associated with natural gas and oil reserve estimates and the history of price volatility in the natural gas and oil markets, events may arise that would require us to record an impairment of the recorded carrying values associated with our natural gas and oil properties.

The exploration, development and operation of natural gas and oil properties involve substantial risks that may result in a total loss of investment.

The business of exploring for and, to a lesser extent, developing and operating natural gas and oil properties involves a high degree of business and financial risk, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Natural gas and oil drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

• availability of capital;

• unexpected drilling conditions;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse changes in prices;

• adverse weather conditions;

• title problems;

• shortages in experienced labor; and

• increases in the cost, or shortages or delays in the delivery, of equipment.

We may drill wells that are unproductive or, although productive, do not produce oil and/or natural gas in economic quantities. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well, or in the event of lower than expected commodity prices. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

The marketability of our production depends mostly upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities, which are owned by third parties.

The marketability of our production depends upon the availability, operation and capacity of natural gas gathering systems, pipelines and processing facilities, which are owned by third parties. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. United States federal, state and foreign regulation of natural gas and oil production and transportation, tax and energy policies, damage to or destruction of pipelines, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market natural gas and oil. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.

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Prices may be affected by local and regional factors.

The prices to be received for our natural gas production will be determined to a significant extent by factors affecting the local and regional supply of and demand for natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process, and transport, our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional natural gas production and the actual (frequently lower) price we receive for our production.

Seasonal weather conditions and wildlife restrictions could adversely affect our ability to conduct operations.

Our operations could be adversely affected by weather conditions and wildlife restrictions. In the Rocky Mountains, certain activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. In addition, a critical habitat designation for certain wildlife under the U.S. Endangered Species Act or similar state laws could result in material restrictions to public or private land use and could delay or prohibit land access or development. The listing of certain species as threatened and endangered could have a material impact on our operations in areas where such listed species are found.

Our industry experiences numerous operating hazards that could result in substantial losses.

The exploration, development and operation of natural gas and oil properties involve a variety of operating risks including the risk of fire, explosions, blowouts, cratering, pipe failure, abnormally pressured formations, natural disasters, acts of terrorism or vandalism, and environmental hazards, including oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. These industry operating risks can result in injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations which could result in substantial losses.

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

The natural gas and oil industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only explore for and produce natural gas and oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas and oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial resources permit. In addition, these companies may have a greater ability to continue exploration and development activities during periods of low natural gas and oil market prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse effect on our business, results of operations, and financial condition.

We may not receive payment for a portion of our future production.

The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. If economic conditions deteriorate, it is likely that situations will occur which will expose us to added risk of not being paid for natural gas or oil that we deliver. We do not attempt to obtain credit protections such as letters of credit, guarantees or prepayments from our purchasers. We are unable to predict what impact the financial difficulties of any of our purchasers may have on our future results of operations and liquidity.

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We have no long-term contracts to sell natural gas and oil.

We do not have any long-term supply or similar agreements with governments or other authorities or entities for which we act as a producer. We are therefore dependent upon our ability to sell natural gas and oil at the prevailing wellhead market price. There can be no assurance that purchasers will be available or that the prices they are willing to pay will remain stable.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We maintain several types of insurance to cover our operations, including worker’s compensation and comprehensive general liability. Amounts over base coverages are provided by primary and excess umbrella liability policies. We also maintain operator’s extra expense coverage, which covers the control of drilling or producing wells as well as redrilling expenses and pollution coverage for wells out of control. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. Terrorist attacks and certain potential natural disasters may change our ability to obtain adequate insurance coverage. The occurrence of a significant event that is not fully insured or indemnified against could materially and adversely affect our financial condition and operations.

We may incur substantial costs to comply with the various federal, state and local laws and regulations that affect our natural gas and oil operations.

We are affected significantly by a substantial amount of governmental regulations that increase costs related to the drilling of wells and the transportation and processing of natural gas and oil. It is possible that the number and extent of these regulations, and the costs to comply with them, will increase significantly in the future. In Colorado, for example, significant governmental regulations have been adopted that are primarily driven by concerns about wildlife and the environment. These government regulatory requirements may result in substantial costs that are not possible to pass through to our customers and which could impact the profitability of our operations.

Our natural gas and oil operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to health and safety, land use, environmental protection or the natural gas and oil industry generally. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Compliance with such laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the incurrence of investigatory or remedial obligations, or the issuance of cease and desist orders.

The environmental laws and regulations to which we are subject may, among other things:

• require applying for and receiving a permit before drilling commences;

• restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

• impose substantial liabilities for pollution resulting from our operations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Over the years, we have owned or leased numerous properties for natural gas and oil activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including CERCLA, RCRA and analogous state laws, we could be held strictly liable for the removal or remediation of previously released materials or property contamination at such locations regardless of whether we were responsible for the release or whether the operations at the time of the release were standard industry practice.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress has considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the natural gas and oil industry in the hydraulic fracturing process, and other legislation regulating hydraulic fracturing has been considered, and in some cases adopted, at various levels of government. Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas wells in shale formations, as well as tight conventional formations, including many of those that we complete and produce. This process involves the injection of water, sand and chemicals under pressure into

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rock formations to stimulate natural gas production. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and/or that hydraulic fracturing could pose a variety of other risks. Any additional level of regulation could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

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.

New environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance. Water that is used to fracture natural gas wells must be removed when it flows back to the wellbore. Our ability to remove and dispose of water will affect our production and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of waste, including produced water, drilling fluids and other wastes associated with the exploration, development and production of natural gas.

We are exposed to credit risk as it affects third parties with whom we have contracted.

Third parties with whom we have contracted may lose existing financing or be unable to obtain additional financing necessary to continue their businesses. The inability of a third party to make payments to us for our accounts receivable, or the failure of our third party suppliers to meet our demands because they cannot obtain sufficient credit to continue their operations, may cause us to experience losses and may adversely impact our liquidity and our ability to make our payments when due.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws applicable to oil and natural gas exploration and production companies. These changes include, but are not limited to:

• the repeal of the limited percentage depletion allowance for oil and natural gas production in the United States;

• the elimination of current deductions for intangible drilling and development costs;

• the elimination of the deduction for certain domestic production activities; and

• an extension of the amortization period for certain geological and geophysical expenditures.

Members of the U.S. Congress have considered similar changes to the existing federal income tax laws that affect oil and natural gas exploration and production companies. It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to U.S. oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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 USEPA 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 USEPA to begin regulating emissions of GHGs under existing provisions of the CAA. The USEPA 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. 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.

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The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business 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 hedging 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, although the CFTC has stated that it will appeal the District Court’s decision.

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 hedging 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 hedges 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.

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

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

Our management, including our Chief Executive Officer and Chief Financial Officer, believes that any disclosure controls and procedures or internal controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, they cannot provide absolute assurance that all control issues and instances of fraud, if any, within our companies have been prevented or detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by an unauthorized override of the controls. The design of any systems 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. The 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.

We have in the past, and in the future may discover, areas of our internal control over financial reporting which may require improvement. Prior to our emergence from bankruptcy, management concluded we had material weaknesses with respect to maintaining an effective financial reporting and closing process to prepare financial statements in accordance with U.S. generally accepted accounting principles. The majority of the factors contributing to our material weaknesses related to the impact the bankruptcy had on critical accounting processes and related accounting resources. At December 31, 2012, management performed an assessment of the design and operating effectiveness of internal control over financial reporting and determined that there were control gaps in our internal control and related processes that require remediation to be performed by management. Furthermore, while completing our December 31, 2012 year end close process, adjustments were identified relating to the application of fresh start

23

accounting that impacted amounts, the presentation of the financial statements and related disclosures previously reported in our quarterly report on Form 10-Q for the quarter ended September 30, 2012. Accordingly, management concluded that these findings were evidence that a material weakness still exists as of December 31, 2012. These material weaknesses have not been remedied 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.

Risks Related to Texadian

Texadian’s risk management strategies may not be effective.

Texadian is exposed to volatility in crude oil prices. To minimize such exposures, inventory levels are monitored when making decisions with respect to risk management. Generally, Texadian only purchases crude oil products for which it has a market and structures its purchase and sales contracts so that price fluctuations for those products do not materially affect the margin it receives. Texadian also seeks to maintain a position that is substantially balanced; however, it may experience net unbalanced positions for short periods of time as a result of transportation and delivery variances, as well as logistical issues associated with inland river conditions. Physical inventory is monitored and managed to a balanced position over a reasonable period of time. Additionally, when delays in delivery or receipt do occur they are hedged using future positions and the resulting gains or losses are recorded as derivative income or losses in the month they are realized. Texadian’s business is also affected by counterparty risk including non-performance by suppliers, vendors and counterparties, fluctuations in crude oil prices, transportation costs, the weather, energy prices, interest rates, and foreign currency exchange rates. Although Texadian may engage in hedging transactions to manage these risks, such transactions may not be successful in mitigating its exposure to these fluctuations and may adversely affect reporting and operating results.

Texadian is subject to numerous laws and regulations globally that could adversely affect operating results.

Texadian is required to comply with the numerous and broad reaching laws and regulations administered by United States federal, state, local, and Canadian governmental agencies relating to, but not limited to, the sourcing, transporting, storing and merchandising of crude oil. Any failure to comply with applicable laws and regulations could subject Texadian to administrative penalties and injunctive relief, civil remedies, including fines, injunctions, and recalls of its products.

Texadian is subject to economic downturns, political instability and other risks of doing business with a globally sourced and traded commodity, which could adversely affect operating results.

If we are not successful in entering into hedging transactions, economic downturns and volatile conditions may have a negative impact on Texadian’s ability to execute its business strategies and on its financial position and its results of operations. Texadian’s results of operations could be affected by changes in trade, monetary and fiscal policies, laws and regulations, and other activities of governments, agencies, and similar organizations, including political conditions, trade regulations affecting production, pricing and marketing of products, local labor conditions and regulations, burdensome taxes and tariffs, enforceability of legal agreements and judgments, and other trade barriers.

Risks Related to our Common Stock

The market for our common stock has been historically illiquid which may affect your ability to sell your shares.

The volume of trading in our stock has historically been low. Since our emergence from bankruptcy, the average daily trading volume for our stock has been approximately 121,500 shares, although the majority of the trading days had volume of less than 5,000 shares. Having a market for shares 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.

Issuance of shares in connection with financing transactions, under stock incentive plans or in settlement of pending claims will dilute current stockholders.

We have outstanding warrants exercisable for 9,592,125 shares of our common stock. In addition, pursuant to our stock incentive plan, our management is authorized to grant stock awards to our employees, directors and consultants. We will likely have to issue additional shares of common stock in satisfaction of unsecured claims which may be allowed by the Bankruptcy Court in the future. You will incur dilution upon the conversion of the warrants, the exercise of any outstanding stock awards or the grant of any

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restricted stock or upon the issuance of shares in satisfaction of claims. In addition, if we raise additional funds by issuing additional common stock, or securities convertible into or exchangeable or exercisable for common stock, further dilution to our existing stockholders will result, and new investors could have rights superior to existing stockholders.

Reduced liquidity and price volatility could result in a loss to investors.

Although our common stock is traded on the OTC Bulletin Board, there can be no assurance as to the liquidity of an investment in our common stock or as to the price an investor may realize upon the sale of our common stock. These prices are determined in the marketplace and may be influenced by many factors, including the liquidity of the market for our common stock, the market price of our common stock, investor perception and general economic and market conditions. This price volatility may make it more difficult for our stockholders to sell shares when they want at prices that they find attractive. We do not know of any one particular factor that has caused volatility in our stock price. However, the stock market in general has experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies. Broad market factors and the investing public’s negative perception of our business may reduce our stock price, regardless of our operating performance.

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

Zell Credit Opportunities Fund, L.P. (“ZCOF”), Whitebox Advisors, LLC (“Whitebox”) and Waterstone Capital Management, L.P. (“Waterstone”) separately own or will have the right to acquire as of March 25, 2013, approximately 36.6%, 27.3% and 19.1%, respectively, or when aggregated, 79.9% 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.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Properties

Piceance Energy

Piceance Energy is a joint venture between the Company and Laramie. All of the assets that Laramie and Delta contributed to Piceance Energy are located within Garfield and Mesa Counties, Colorado and are within a 10-mile radius in the Piceance Basin geologic province. All of the natural gas and oil reserves associated with such assets produce from the same geologic formations, the Mesaverde and Mancos Formations, and some of the acreage is contiguous. Laramie and its predecessor company have drilled over 300 natural gas wells with over a 99% success rate in the Piceance Basin. Laramie is the manager of Piceance. Piceance Energy is owned 66.66% by Laramie and 33.34% by our wholly-owned subsidiary, Par Piceance Energy Equity.

Our core asset is our minority equity investment in Piceance Energy. Piceance Energy’s primary area of activity is in the Piceance Basin in western Colorado. The Williams Fork member of the Mesaverde formation is the primary producing interval and has been successfully developed throughout the Piceance Basin. 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.

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 through the February 2008 agreement with Encana.

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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 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 requires reserves to be in compliance with the SEC definitions and guidance, and for reserves 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, 2012 has been filed as a part of Exhibit 99.1 to this 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.

Reserves Reported to Other Agencies

On July 6, 2012, we filed a report with the Bankruptcy Court with respect to our estimated natural gas and oil reserves that were contributed to Piceance Energy as a part of the bankruptcy process. We did not file any other report with a federal authority or agency other than the SEC with respect to our estimates of natural gas and oil reserves.

Proved Undeveloped Reserves

Substantially all of our proved undeveloped reserves at December 31, 2012 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.

Impairment of Long Lived Assets

We periodically compare our historical cost basis of each proved developed and undeveloped oil and gas property to its expected future undiscounted net cash flow from each property (on a field by field basis). Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future net cash flows exceed the carrying value of the property, no impairment is recognized. If the carrying value of the property exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. As a result of this assessment, during the period from January 1, 2012 through August 31, 2012 and during the year ended December 31, 2011, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties and other items of approximately $151.3 million and $420.4 million, respectively. At August 31, 2012, the impairment charge we recorded was the result of various transactions resulting from our emergence from Chapter 11 and from the application of fresh start accounting effective September 1, 2012.

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At December 31, 2011, our 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. At August 31, 2012, the impairment recorded was a result of various transactions resulting from the emergence from Chapter 11 and the application of fresh start accounting. Subsequent to the end of the reporting period, in August 2012, the Bankruptcy Court approved a plan of sale of substantially all of our assets and accordingly these assets are classified as held for sale in reporting period at June 30, 2012 and were subject to a material write-down to fair value at that time.

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 the respective periods in 2012 and the years ended December 31, 2011 and 2010.

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012		Year Ended December 31,
						2011			2010
Company:
Production volume -
Total production (MMcfe)		139			5,256		11,682			16,763
Production from continuing operations:
Oil (MBbls)		22			67		140			161
Natural Gas (MMcf)		9			4,852		9,948			10,265
Total (MMcfe)		139			5,256		10,788			11,231
Net average daily production-continuing operations:
Oil (Bbl)		177			277		385			442
Natural Gas (Mcf)		41			19,966		27,254			28,127
Average sales price:
Oil (per Bbl)	$	97.66		$	96,60	$	80.16		$	60.75
Natural Gas (per Mcf)	$	4.32		$	3.42	$	5.29		$	5.06
Hedge gain (loss) (per Mcfe)	$	—		$	—	$	(0.04	)	$	(0.52	)
Lease operating costs—(per Mcfe)	$	11.22		$	1.72	$	1.27		$	1.57
Company Share of Piceance Energy:
Production volume -
Total production (MMcfe)		1,425
Production from continuing operations:
Oil (MBbls)		6
NGLs (MBbls)		48
Natural Gas (MMcf)		1,391
Total (MMcfe)		1,425
Net average daily production-continuing operations:
Oil (Bbl)		46
NGLs (Bbl)		391
Natural Gas (Mcf)		11,404
Average sales price:
Oil (Per Bbl)	$	77,81
NGLs (Per Bbl)	$	36.09
Natural Gas (per Mcf)	$	3.09
Hedge gain (loss) (per Mcfe)	$	(0.21	)
Lease operating costs—(per Mcfe)	$	0.63

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Productive Wells and Acreage

The table below shows, as of December 31, 2012, 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.

	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		2.1		—		—		2,422		147
Colorado		—		—		8		0.40		80		4
Total		34		2.1		8		0.40		2,502		151
New Mexico(4)		—		—		7		0.09		560		7
Total		34		2.1		15		0.49		3,062		158
Company’s Share of Piceance Energy
Colorado (5)		—		—		516		99.86		8,159		2,349
Total		—		—		531		100.35		11,221		2,507

(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, 2012, we held undeveloped acreage by state as set forth below:

	Undeveloped Acres (1)(2)
Location	Gross		Net
Company:
Colorado		140		7
Company’s Share of Piceance Energy:
Colorado (3)		38,363		11,062

(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, 2012 has not already been impaired in consideration of these expirations or capital budgeted to convert acreage to HBP.

(3) For our 33.34% equity interest in Piceance Energy, the net undeveloped acres is reflected as if we owned our interest directly.

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Drilling Activity

During the respective periods in 2012 and the years ended December 31, 2011 and 2010, we drilled or participated in the drilling of the following productive and nonproductive exploratory and development wells:

	Successor				Predecessor
									Year Ended December 31,
	Period from September 1 Through December 31, 2012				Period from January 1 Through August 31, 2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Company:
Exploratory Wells (2):
Productive:
Oil		—		—		—		—		—		—		—		—
Natural Gas		—		—		1		0.32		1		1		—		—
Nonproductive		—		—		—		—		1		1		—		—
Total		—		—		1		0.32		2		2		—		—
Development Wells (1):
Productive:
Oil		—		—		—		—		—		—		1		1.00
Natural Gas		8		0.40		—		—		41		1.96		66		16.10
Nonproductive		—		—		—		—		—		—		1		0.25
Total		8		0.40		—		—		41		1.96		68		17.35
Total Wells (1):
Productive:
Oil		—		—		—		—		—		—		1		1.00
Natural Gas		8		0.40		1		0.32		42		2.96		66		16.10
Nonproductive		—		—		—		—		1		1		1		0.25
Total Wells		8		0.40		1		0.32		43		3.96		68		17.35
Company’s Share of Piceance Energy
Exploratory Wells (2):
Productive:
Oil		—		—
Natural Gas		—		—
Nonproductive		—		—
Total		—		—
Development Wells (1):
Productive:
Oil		—		—
Natural Gas		—		—
Nonproductive		—		—
Total		—		—
Total Wells (1):
Productive:
Oil		—		—
Natural Gas		—		—
Nonproductive		—		—
Total Wells		—		—

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

(2) Does not include exploratory wells in progress.

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Present Drilling Activity

At December 31, 2012, we had 14 development wells in the Piceance Basin area that are in the process of being drilled or expect to be drilled during 2013. These 14 wells are part of a 22 well drilling program with Encana. During 2012, eight of the wells were drilled and are now producing or are awaiting hookup. Additionally, we drilled one exploratory well during late 2011, which was contributed to Piceance Energy and completed during December 2012.

Delivery Commitments

We had no material delivery commitments as of December 31, 2012.

Item 3. Legal Proceedings

From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of our business. As of the date of this 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, 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 OTC Bulletin Board. 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 147.7 million shares of common stock to settle unsecured claims pursuant to the Plan. On July 12, 2011, the stockholders of Delta approved a one-for-ten reverse split of the common stock which became effective on July 13, 2011.

The following quotations reflect inter-dealer high and low sales prices, without retail mark-up, mark-down or commission (price per share of common shares prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis) and may not represent actual transactions.

Quarter Ended	High		Low
March 31, 2011	$	11.70	$	7.22
June 30, 2011		9.20		4.80
September 30, 2011		4.57		0.42
December 31, 2011		2.41		0.10
March 31, 2012		0.68		0.08
June 30, 2012		0.61		0.08
September 30, 2012		1.45		0.05
December 31, 2012		1.20		1.02

On March 22, 2013, the closing price of our common stock was $1.23 on the OTC Bulletin Board. 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.

Recent Sales of Unregistered Securities

During the year ended December 31, 2012, we did not have any sale 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

We did not purchase any of our own common stock during the year ended December 31, 2012.

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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

Reorganization under Chapter 11

On December 16, 2011, Delta Petroleum Corporation (“Delta”) and its subsidiaries Amber Resources Company of Colorado, DPCA, LLC, Delta Exploration Company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc. and Castle Texas Production Limited Partnership 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”). On January 6, 2012, Castle Exploration Company, Inc., a subsidiary of Delta Pipeline, LLC, also filed a voluntary petition under Chapter 11 in the Bankruptcy Court. Delta and its subsidiaries included in the bankruptcy petitions are collectively referred to as the “Debtors.”

On December 27, 2011, the Debtors filed a motion requesting an order to approve matters relating to a proposed sale of Delta’s assets, including bidding procedures, establishment of a sale auction date and establishment of a sale hearing date. On January 11, 2012, the Bankruptcy Court issued an order approving these matters. On March 20, 2012, Delta announced that it was seeking court approval to amend the bidding procedures for its upcoming auction to allow bids relating to potential plans of reorganization as well as asset sales. On March 22, 2012, the Bankruptcy Court approved the revised procedures.

Following the auction, 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 connection with the Plan, Delta entered into a non-binding term sheet describing a transaction by which Laramie and Delta intended to form a new joint venture called Piceance Energy LLC (“Piceance Energy”). On June 4, 2012, Delta entered into a Contribution Agreement (the “Contribution Agreement”) with Piceance Energy and Laramie to effect the transactions contemplated by the term sheet.

On June 4, 2012, the Debtors filed a disclosure statement relating to the Plan. The Plan was confirmed on August 16, 2012 and 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 to Piceance Energy their respective assets in the Piceance Basin. Piceance Energy is owned 66.66% by Laramie and 33.34% by Delta (referred to after the closing of the transaction as “Successor”). 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 repaid 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 147.7 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. For a description of this agreement, see “– Piceance Energy – Piceance Energy LLC Agreement” below.

In addition, Laramie and Piceance Energy entered into a Management Services Agreement pursuant to which Laramie agreed to provide certain services to Piceance Energy for a fee of $650,000 per month.

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 its shares. The purpose of this provision is to preserve certain of our tax attributes that we believe may have value. Under the amended and restated bylaws, the Company board of directors has five members, each of whom was appointed by our stockholders pursuant to a Stockholders’ Agreement entered into on the Emergence Date.

Fresh Start Accounting and the Effects of the Plan

As required by U.S. generally accepted accounting principles (“U.S. GAAP”), effective as of August 31, 2012, we adopted fresh start accounting following the guidance of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852 “Reorganizations” (“ASC 852”). Fresh start accounting 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

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operations of Delta prior to reorganization (hereinafter also referred to as “Predecessor”) and are not comparable to consolidated financial statements presented on or after August 31, 2012. Fresh start accounting 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 accounting results in a new basis of accounting and reflects the allocation of our estimated fair value to underlying assets and liabilities. The effects of our implementation of the Plan and related fresh start adjustments are reflected in the results of operations of the Predecessor for 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 addition, the cancellation of debt income and the allocation of the attribute reduction for tax purposes is an estimate and will not be finalized until the 2012 tax return is filed sometime in 2013. Any change resulting from this estimate could impact deferred taxes.

Under ASC 852, 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 accounting, 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 “– Critical Accounting Policies and Estimates – Fair Value Measurements” below 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 accounting reflects the value of the Successor as determined in the confirmed Plan. Under fresh start accounting, our asset values are remeasured and allocated based on their respective fair values in conformity with the acquisition method of accounting for business combinations in FASB ASC Topic 805, “Business Combinations” (“ASC 805”). The reorganization values approximated the fair values of the identifiable net assets. Liabilities existing as of the Emergence 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 section 1124(1) of the Bankruptcy Code. Each general unsecured claim and noteholder claims received its pro rata share of new common stock in full satisfaction of its claims.

Piceance Energy

Laramie is a Denver-based company primarily focused on finding and developing natural gas reserves from unconventional gas reservoirs within the Rocky Mountain Region. Its predecessor company, Laramie Energy, LLC (“Laramie I”), sold all of its natural gas and oil assets in May 2007 to Plains Exploration & Production Company, Inc. Laramie was formed in June 2007 by Laramie I executives and former employees and by affiliates of the private equity investors in Laramie I. Laramie is backed by equity capital commitments funded by Laramie’s management team, EnCap Investments, Avista Capital, and DLJ Merchant Banking Partners (an affiliate of Credit Suisse Securities).

All of the assets contributed to Piceance Energy are located within Garfield and Mesa Counties, Colorado and are within a 10-mile radius in the Piceance Basin geologic formation. All of the oil and natural gas reserves contributed to Piceance Energy produce from the same geologic formations, the Mesaverde and Mancos Formations, and some of the contributed acreage is contiguous.

Piceance Energy LLC Agreement

In connection with the consummation of the Contribution Agreement as discussed above, Laramie and Par Piceance Energy Equity LLC, one of our wholly owned subsidiaries (“Par Piceance Energy Equity”), entered into a limited liability company agreement (the “LLC Agreement”) that governs the operations of Piceance Energy. The business of Piceance Energy is to own the oil and natural gas, surface real estate, and related assets formerly owned by Laramie and the Company in Garfield and Mesa Counties, Colorado, or other assets subsequently acquired by Piceance Energy, and to operate such assets. Pursuant to the LLC Agreement, Piceance is managed by Laramie, which controls its day-to-day operations, subject to the supervision of a six-person board, four (4) of which were appointed by Laramie and two (2) of which were appointed by Par Piceance Energy Equity. Certain major decisions

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require the unanimous consent of the board. The LLC Agreement provides that the sole manager, which is initially Laramie, 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, if approved by a majority of the board. If any member does not fund their share of the capital call, their interest may be reduced or diluted by the amount of the shortfall. The 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 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.

Piceance Energy Credit Facility

On June 4, 2012, Piceance Energy entered into a credit facility, (as amended, the “Piceance Energy Credit Facility”), with J.P. Morgan Securities LLC and Wells Fargo Securities LLC, each as an arranger, JPMorgan Chase Bank, N.A., as the administrative agent (the “Administrative Agent”), and the lenders party thereto. The Piceance Energy Credit Facility is a $400 million secured revolving credit facility secured by a lien on Piceance Energy’s oil and gas properties and related assets. Par Piceance Energy Equity and Laramie are each guarantors of the Piceance Energy Credit Facility, with recourse limited to the pledge of the equity interests of Par Piceance Energy Equity and Laramie in Piceance Energy.

Availability under the Piceance Energy Credit Facility is limited to the lesser of (i) $400 million or (ii) the borrowing base in effect from time to time. The initial borrowing base at the Effective Date was set at $140 million. The borrowing base is determined by the Administrative Agent and the lenders, in their sole discretion, based on customary lending practices, review of the oil and gas properties included in the borrowing base, financial review of Piceance Energy, and such other factors as may be deemed relevant. The borrowing base is redetermined (i) on or about March 15 of each year based on the previous December 31 reserve report prepared by an independent engineering firm acceptable to the Administrative Agent, and (ii) on or about September 15 of each year based on the previous June 30 reserve report prepared by Piceance Energy’s internal engineers. The borrowing base was redetermined March 15, 2013 and set at $140 million. In connection with the consummation of the Contribution Agreement, Piceance Energy borrowed $100 million under the Piceance Energy Credit Facility and distributed approximately $72.6 million of that amount to us and approximately $24.9 million to Laramie. The total amount outstanding as of December 31, 2012 is $90 million.

The Piceance Energy Credit Facility will mature on June 4, 2016. Amounts borrowed bear interest at rates ranging from LIBOR plus 1.75% to LIBOR plus 2.75% per annum for Eurodollar loans and the prime rate plus 0.75% to prime rate plus 1.75% per annum for Base Rate loans, depending upon the ratio of outstanding credit to the borrowing base. The agreement contains customary operational and financial covenants, including a current ratio covenant, a total debt to consolidated EBITDAX covenant and a borrowing base covenant. At December 31, 2012, Piceance Energy was in compliance with all such covenants. Under the terms of the Piceance Energy Credit Facility, Piceance Energy is generally prohibited from making future cash distributions to its owners, including Par Piceance Energy Equity.

2012 Operations Overview

During the first eight months of 2012, we focused on our restructuring while operating as a debtor in possession under Chapter 11 of the U.S. Bankruptcy Code. Our operations consisted of maintaining and operating existing natural gas and oil properties with no significant exploration or drilling activities. Effective August 31, 2012, we emerged from Chapter 11 of the U.S. Bankruptcy Code. Since then, our operations in 2012 primarily consisted of activities related to our minority ownership interest in Piceance Energy.

Results of Operations

The following discussion and analysis relates to items that have affected the Successor’s results of operations for the period from September 1 through December 31, 2012, and the results of operations of the Predecessor for the period from January 1, 2012 through August 31, 2012 and the year ended December 31, 2011.

Successor—Period from September 1, 2012 through December 31, 2012

This four month period has been presented due to the application of fresh start accounting effective August 31, 2012 and includes primarily operating activities from our seven wells and our equity investment in Piceance Energy.

Net Loss Attributable to Common Stockholders. Net loss attributable to common stockholders was approximately $8.8 million, or a loss of $0.06 per diluted common share, for the period from September 1 through December 31, 2012.

Oil and Gas Sales. For the period from September 1 through December 31, 2012, oil and gas sales were approximately $2.1 million. In the future, we expect oil and natural gas sales revenues to be substantially less than the Predecessor as the majority of its assets were contributed to Piceance Energy.

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Lease Operating Expense. For the period from September 1 through December 31, 2012, lease operating expense was approximately $1.7 million. In the future, we expect lease operating expenses to be substantially less than the Predecessor as the majority of its assets were contributed to Piceance Energy.

Production Taxes. For the period from September 1 through December 31, 2012, production taxes were approximately $4,000. In the future, we expect production taxes to be substantially less than the Predecessor as the majority of its assets were contributed to Piceance Energy.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion was approximately $401,000 for the period from September 1 through December 31, 2012.

General and Administrative Expense. Our general and administrative expense was approximately $5.1 million for the period from September 1 through December 31, 2012 consisting primarily professional fees, transaction costs related to the Texadian acquisition, wind down of the Predecessor’s operations and other general administrative expenses.

Loss From Unconsolidated Affiliates. Our allocated loss from Piceance Energy totaled approximately $1.3 million for the period from September 1 through December 31, 2012 which includes an approximate $306,000 loss from derivative obligations and a loss of approximately $700,000 from operating activities and the remainder attributable to financing activities. Piceance Energy is expected to continue to have losses in the future until natural gas prices improve.

Interest Expense and Financing Costs. Our interest expense and financing costs were approximately $1.1 million for the period from September 1 through December 31, 2012 consisting of interest accrued in kind totaling approximately $465,000 and amortization of debt discount related to our Loan Agreement totaling approximately $591,000.

Unrealized Loss of Derivative Instruments. For the period from September 1, 2012 through December 31, 2012, we recognized an unrealized loss on our embedded derivative and warrant derivative liabilities of approximately $4.3 million due to mark to market adjustments resulting from an increase in the price of our common stock.

Income Taxes. For the period from September 1, 2012 through December 31, 2012, we recorded a net income tax benefit of $2,757, which represents the amount of our valuation allowance that was reduced as a result of deferred tax liabilities that were recorded on the acquisition of Texadian Energy. We determined it was more likely than not that our tax attributes, including our net operating loss carryover would be allowed to reduce the future reversal of temporary differences that were recorded in association with certain intangible assets that were acquired in the Texadian Energy acquisition.

Predecessor – Period from January 1, 2012 through August 31, 2012 compared to the year ended December 31, 2011

The 2012 and 2011 periods generally lack comparability due to an eight month period presented compared to a twelve month period, curtailment of exploration and drilling activity in 2012 due to the bankruptcy resulting in a decline in production and significant oil and natural gas asset impairments taken in both periods. In addition, reorganization items were incurred in 2012 as a result of our Chapter 11 bankruptcy proceedings which were not incurred in 2011.

Net Loss Attributable to Common Stockholders. For the reasons discussed above, net loss attributable to common stockholders was approximately $45.4 million, or a loss of $1.57 per diluted common share, for the period from January 1, 2012 through August 31, 2012, compared to a net loss attributable to common stockholders of approximately $470.1 million, or a loss of $16.30 per diluted share of common stock, for the year ended December 31, 2011.

Oil and Gas Sales. During the period from January 1, 2012 through August 31, 2012, oil and gas sales decreased 64% to approximately $23.1 million, as compared to approximately $63.9 million for the year ended December 31, 2011. In addition to the reasons noted above, the decrease was also a result of lower natural gas prices.

Lease Operating Expense. Lease operating expenses for the period from January 1, 2012 through August 31, 2012 decreased 35% to approximately $9.0 million, as compared to approximately $13.8 million for the year ended December 31, 2011. In addition to the reasons noted above, the decrease was partially offset by increases to operating costs associated with our properties offshore California.

Transportation Expense. Transportation expense for the period from January 1, 2012 through August 31, 2012 decreased 50% to approximately $7.0 million from approximately $13.9 million for the year ended December 31, 2011 primarily due to the reasons noted above.

Production Taxes. Production taxes for the period from January 1, 2012 through August 31, 2012 decreased 35% to approximately $979,000 from approximately $1.5 million for the year ended December 31, 2011 primarily due to the reasons noted above and adjustments in the effective Colorado severance and local ad valorem withholding tax rates.

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Dry Hole Costs and Impairments. Dry hole costs and impairments for the period from January 1, 2012 through August 31, 2012 decreased 64% to approximately $151.3 million from approximately $420.4 million for the year ended December 31, 2011 due to impairments taken for our natural gas and oil properties in 2011. The impairments taken in the third quarter of 2011 relate to a fair value adjustment to our natural gas and oil gas properties as a result of offers received during our strategic process prior to entering into Chapter 11. 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 a fair value impairment of approximately $151.3 million.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion expense decreased 59% to approximately $16.0 million for the period from January 1, 2012 through August 31, 2012, as compared to approximately $39.1 million for the year ended December 31, 2011 primarily due to the reasons noted above.

General and Administrative Expense. General and administrative expense decreased 67% to approximately $9.4 million for the period from January 1, 2012 through August 31, 2012, as compared to approximately $28.1 million for the year ended December 31, 2011. The decrease in general and administrative expenses is attributed to a decrease in non-cash stock compensation expense and to reduced staffing as a result of attrition and a reduction in work force since 2011, resulting in lower cash compensation and administrative operating expense.

Reorganization Items. For the period from January 1 through August 31, 2012, we recognized approximately $22.4 million in professional fees and administrative expenses, a loss of approximately $14.8 million related to a change in fair value of assets due to fresh start accounting adjustments, a gain on the extinguishment of debt of approximately $166.1 million related to the settlement of our senior debt and a gain of approximately $2.2 million related to the settlement of liabilities subject to compromise. For the year ended December 31, 2011, reorganization items were not significant.

Discontinued Operations. The results of operations relating to property interests sold in the 2011 have been reflected as discontinued operations.

Income Tax Expense (Benefit). Due to our continued losses, we were required by the “more likely than not” threshold for assessing the realizability of deferred tax assets, to record a valuation allowance for our net deferred tax assets.

Liquidity and Capital Resources

Prior to our bankruptcy filing, our sources of liquidity and capital resources were cash provided through the issuance of debt and equity securities when market conditions permitted, operating activities, sales of oil and gas properties, and borrowings under our credit facilities. During bankruptcy proceedings, our principal sources of liquidity and capital resources were borrowings under the DIP Credit Facility described below and cash flows from operating activities. As of December 31, 2012, we have access to our Loan Agreement, as described below, under which we had $17.0 million available for future borrowings and unrestricted cash of $6.2 million. Since the Emergence Date, the primary uses of our capital resources have been in the operation of natural gas and oil properties, acquisitions, professional fees, and bankruptcy expenses.

Our principal asset since the consummation of the Plan and our emergence from bankruptcy is a minority interest in Piceance Energy. Piceance Energy’s primary sources of liquidity will be cash from operations and borrowings under the Piceance Energy Credit Facility. Our liquidity is constrained by the restrictions on Piceance Energy’s ability to distribute cash to us under the Piceance Energy Credit Facility, by our need to satisfy our obligations under the Loan Agreement, and by potential capital contributions required to be made by us to Piceance Energy. We also expect to have modest cash flows from certain assets not contributed to Piceance Energy pursuant to the Contribution Agreement on the Emergence Date.

We may be required to fund capital contributions of up to $20 million to Piceance Energy under the LLC Agreement. We expect that our capital contributions will be funded from available cash on hand, advances under the Loan Agreement, 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.

Debtor in Possession Credit Agreement

On December 21, 2011, the Predecessor entered into a senior secured debtor-in-possession credit facility (the “DIP Credit Facility”) in connection with the bankruptcy filing. Up to $57.5 million could be borrowed under the DIP Credit Facility, of which approximately $45 million was initially drawn by the Predecessor to repay all amounts outstanding under its previous credit agreement, which was then terminated. The DIP Credit Facility was amended in March 2012 to increase the maximum borrowing capacity by $1.4 million to $58.9 million. All of the loans under the DIP Credit Facility were term loans. The interest rate under the DIP Credit Facility was 13% plus 6% per annum in payment-in-kind interest. The initial maturity date of the DIP Credit Facility was June 30, 2012. The Predecessor subsequently entered into a series of forbearance agreements extending the maturity date to August 31, 2012. The DIP Credit Facility was repaid in full and terminated in accordance with the Plan.

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Notes

The bankruptcy filing constituted an event of default under the Company’s 7% Series A Senior Notes due 2015 (the “7% Notes”) and the Company’s 3 ³/₄% Convertible Senior Note due 2037 (the “3 ³/₄% Notes” and, together with the 7% Notes, the “Notes”). Under the indentures governing the Notes, all principal, interest and other amounts due relating to the Notes became immediately due and payable. The Notes were settled in accordance with the terms of the Plan.

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 $30.0 million. We borrowed $13.0 million on the Effective Date in order to, along with the proceeds from the Contribution Agreement, (i) repay the loans and obligations due under the DIP Credit Facility, and (ii) pay allowed but unpaid administrative expenses to the Debtors related to the Plan.

Below are certain of the material terms of the Loan Agreement:

Interest. At our election, any Loans will bear interest at a rate equal to 9.75% per annum payable either (i) in cash, quarterly, in arrears at the end of each calendar quarter or (ii) in-kind, accruing quarterly. In addition, all repayments due under the Loan Agreement will be charged a minimum of a 3% repayment premium. Accordingly, we will accrete amounts due for the minimum repayment premium over the term of loan using the effective interest method.

At any time after an event of default under the Loan Agreement has occurred and is continuing, (i) all outstanding obligations will, to the extent permitted by applicable law, bear interest at a rate per annum equal to 11.75% and (ii) all interest accrued and accruing will be payable in cash on demand.

Prepayment. We may prepay Loans at any time, in any amount. Such prepayment is to include all accrued and unpaid interest on the portion of the obligations being prepaid through the prepayment date. If at any time within the twelve months following the Emergence Date, we prepay the obligations due, in whole, but not in part, then in addition to the repayment of 100% of the principal amount of the obligations being prepaid plus accrued and unpaid interest thereon, we are required to pay the interest that would have accrued on the prepaid amount through the first anniversary of the Emergence Date plus a 6% prepayment premium.

In addition to the above described prepayment premium, we will pay a repayment premium equal to the percentage of the principal repaid during the following periods:

Period	Repayment Premium
From the Emergence Date through the first anniversary of the Emergence Date		6	%
From the day after the first anniversary of the Emergence Date through the second anniversary of the Emergence Date		5	%
At all times from and after the day after the second anniversary of the Emergence Date		3	%

We are also required to make certain mandatory repayments after certain dispositions of property, debt issuances, joint venture distributions from Piceance Energy, casualty events and equity issuances, in each case subject to customary reinvestment provisions. These mandatory repayments are subject to the prepayment premiums described above.

The contingent repayments described above are required to be accounted for as an embedded derivative. The estimated fair of the embedded derivative at issuance was approximately $65,000 and was recorded as a derivative liability with the offset to debt discount. Subsequent changes in fair value are reflected in earnings.

Collateral. The Loans and all obligations arising under the Loan Agreement are secured by (i) a perfected, first-priority security interest in all of our assets other than our equity interest in Piceance Energy held by Par Piceance Energy Equity, pursuant to a pledge and security agreement made by us and certain of our subsidiaries in favor of the Agent, and (ii) a perfected, second-lien security interest in our equity interest in Piceance Energy held by Par Piceance Energy Equity, pursuant to a pledge agreement by Par Piceance Energy Equity in favor of the Agent. The priority of the Lenders’ security interest in our assets is specified in that certain intercreditor agreement (the “Intercreditor Agreement”), among JPMorgan Chase Bank, N.A., as administrative agent for the First Priority Secured Parties (as defined in the Intercreditor Agreement), the Agent, as administrative agent for the Second Priority Secured Parties (as defined in the Intercreditor Agreement), the Company and Par Piceance Energy Equity.

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Guaranty. All of our obligations under the Loan Agreement are unconditionally guaranteed by the Guarantors.

Fees and Commissions. We agreed to pay the Agent an annual nonrefundable administrative fee that was earned in full on the Effective Date. In addition, we agreed to pay the Lenders a nonrefundable closing fee that was earned in full on the Effective Date.

Warrants. As consideration for granting the Loans, we have also issued warrants to the Lenders to purchase shares of our common stock as described under “– Warrant Issuance Agreement” below.

Term. All loans and all other obligations outstanding under the Loan Agreement are payable in full on August 31, 2016.

Covenants. The Loan Agreement has no financial covenants that we are required to comply with; however, it does require us to comply with various affirmative and negative covenants affecting our business and operations which we are in compliance with at December 31, 2012.

Amendment to the Loan Agreement – Tranche B Loan

On December 28, 2012, in order to fund a portion of the purchase price for our acquisition of Texadian Energy (see “–Capital and Exploration Expenditures” below), the Loan Parties entered into an amendment to the Loan Agreement with the Agent and the Lenders, pursuant to which the Lenders agreed to extend additional borrowings to us (the “Tranche B Loan”). The total commitment of the Tranche B Loan of $35.0 million was drawn at closing. In addition to funding a portion of the purchase price of the acquisition of Texadian Energy, Inc., formerly known as Seacor Energy, Inc. (“Texadian”), the Tranche B Loan provides cash collateral for the letter of credit facility with Compass Bank (as described below).

Set forth below are certain of the material terms of the Tranche B Loan:

Interest. At our election, the Tranche B Loan will bear interest at a rate equal to 9.75% per annum payable either (i) in cash or (ii) in-kind.

At any time after an event of default has occurred and is continuing, (i) all outstanding obligations will, to the extent permitted by applicable law, bear interest at a rate per annum equal to 11.75% and (ii) all interest accrued and accruing will be payable in cash on demand.

Prepayment. We may prepay the Tranche B Loan 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 Tranche B Loan.

Collateral. The Tranche B Loan is secured by a lien on substantially all of our assets and our subsidiaries, including Texadian, but excluding our equity interests in Piceance Energy.

Guaranty. All of our obligations under the Tranche B Loan are unconditionally guaranteed by the Guarantors, including, Texadian.

Maturity date. The maturity date is July 1, 2013.

Fees and Commissions. We agreed to pay the Lenders a nonrefundable exit fee equal to five percent (5%) of the aggregate amount of the Tranche B Loan. The exit fee is earned in full and payable on the maturity date of the Tranche B Loan or, if earlier, the date on which the Tranche B Loan is paid in full.

Letter of Credit Facility

On December 27, 2012, we entered into a letter of credit facility agreement with Compass Bank, as the lender (the “Compass Letter of Credit Facility”). The Compass Letter of Credit Facility, which matures on December 26, 2013, provides for a letter of credit facility in an aggregate principal amount of $30.0 million that is available for the issuance of cash-collateralized standby letters of credit for us or any of our subsidiaries’ account. Letters of credit issued under the Compass Letter of Credit Facility are secured by an amount of cash pledged and delivered by us to Compass equal to one hundred five percent (105%) of the undrawn amount of all outstanding letters of credit. We agreed to pay a letter of credit fee equal to one and one half percent (1.5%) per annum of the stated face amount of each letter of credit for the number of days such letter of credit is to remain outstanding plus standard and customary administrative fees. The Compass Letter of Credit Facility does not contain any financial covenants; however, it does require us to comply with various affirmative and negative covenants affecting our business and operations.

In connection with the acquisition of Texadian, Compass Bank issued an Irrevocable Standby Letter of Credit in favor of SEACOR Holdings in the amount of $11.71 million (the “Irrevocable Standby Letter of Credit”). The Irrevocable Standby Letter of Credit will secure SEACOR Holdings in the event that either of the following letters of credit is drawn: (i) the letter of credit issued by DNB Bank, ASA in favor of Suncor Energy Marketing Inc., with an original maturity date of February 5, 2013; or (ii) the letter of credit issued by DNB Bank, ASA in favor of Cenovus Energy Marketing Services Limited, with an original maturity date of February 5, 2013. These letters of credit have been terminated and released.

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Warrant Issuance Agreement

Pursuant to the Plan, on the Emergence Date, we issued to the Lenders warrants (the “Warrants”) to purchase up to an aggregate of 9,592,125 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 $0.01 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 Warrant Shares issued on the Effective Date was determined based on the number of shares of our common stock issued as allowed claims on or about the Effective Date by the Bankruptcy Court pursuant to the Plan. The Warrant Issuance Agreement provides that the number of Warrant Shares and the Exercise Price shall be adjusted in the event that any additional shares of common stock or securities convertible into common stock (the “Unresolved Bankruptcy Shares”) are authorized to be issued under the Plan by the Bankruptcy Court after the Effective Date as a result of any unresolved bankruptcy claims under the Plan. Upon each issuance of any Unresolved Bankruptcy Shares, the Exercise Price shall be reduced to an amount equal to the product obtained by multiplying (A) the Exercise Price in effect immediately prior to such issuance or sale, by (B) a fraction, the numerator of which shall be (x) 147,655,815 and (y) the denominator of which shall be the sum of (1) 147,655,815 and (2) and the number of additional Unresolved Bankruptcy Shares authorized for issuance under the Plan. Upon each such adjustment of the Exercise Price, the number of Warrant Shares shall be increased to the number of shares determined by multiplying (A) the number of Warrant Shares which could be obtained upon exercise of such Warrant immediately prior to such adjustment by (B) a fraction, the numerator of which shall be the Exercise Price in effect immediately prior to such adjustment and the denominator of which shall be the Exercise Price in effect immediately after such adjustment. In the event that any Lender or its affiliates fails to fund its pro rata portion of any Loans required to be made under the Loan Agreement, then the number of Warrant Shares exercisable under the Warrants held by such Lender will be reduced to an amount equal to the product of (i) the number of Warrant Shares initially exercisable under the Warrant held by the Lender and (ii) a fraction equal to one minus the quotient obtained by dividing (x) the amount of Loans previously made under the Loan Agreement by such Lender by (y) such Lender’s full commitment for Loans.

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.

Cash Flows

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012			Year Ended December 31, 2011
				(In thousands)
Net cash provided by (used in) operating activities	$	(4,636	)	$	(20,262	)	$	990
Net cash provided by (used in) investing activities	$	(17,690	)	$	72,622		$	87,649
Net cash provided by (used in) financing activities	$	23,629		$	(60,340	)	$	(89,967	)

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Net cash used in operating activities was approximately $4.6 million for the period from September 1 through December 31, 2012 and approximately $20.2 million of cash was used in operating activities for the eight months ended August 31, 2012 and approximately $990,000 of cash was provided by operating activities for year ended December 31, 2011. Cash flows from operating activities for the eight months ended August 31, 2012 as compared to the year ended December 31, 2011 were primarily impacted by the decreased level of operations in 2012 compared to 2011 as a result of the bankruptcy.

For the period from September 1, 2012 through December 31, 2012, cash used in investing activities was primarily related to our acquisition of Texadian totaling 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 totaling approximately $74.2 million ($72.6 million net after working capital adjustments made in subsequent periods). Cash provided by investing activities was approximately $87.6 million for the year ended December 31, 2011 and was generated by the return of a restricted deposit of approximately $100.0 million, and proceeds from asset sales of approximately $45.2 million offset by the asset purchases totaling approximately $57.6 million.

Net cash provided by financing activities for the period from September 1 through December 31, 2012 was primarily related to borrowing of $35 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 our Compass Letter of Credit Facility. 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 DIP Credit Facility 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. Net cash used in financing activities was approximately $90.0 million for the year ended December 31, 2011. In that period, we received approximately $117.6 million in borrowings and made repayments of borrowings of approximately $105.0 million and installment payments on property acquisitions of approximately $100.0 million.

Capital and Exploration Expenditures

We made no capital and exploration expenditures for the period from September 1, 2012 through December 31, 2012. Our capital and exploration expenditures for the period from January 1, 2012 through August 31, 2012 and the year ended December 31, 2011 were approximately $1.6 million and $56.0 million, respectively.

We currently have no material planned future capital expenditures. Amounts 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 million if approved by the majority of its board of directors. We also continue to seek strategic investments in business opportunities, but the amount and timing of those investments are not predictable.

On December 31, 2012, we acquired Texadian, an indirect wholly-owned subsidiary of SEACOR Holdings Inc., for approximately $14.0 million plus estimated net working capital of approximately $4.0 million at closing. Texadian operates a crude oil sourcing, marketing, transportation, distribution and marketing business with significant logistics capabilities in historical pipeline shipping status, a railcar fleet and tow and barge chartering. We acquired Texadian in furtherance of our growth strategy that focuses on the acquisition of income producing businesses.

Commitments and Contingencies

On 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.

On September 19, 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. Further distributions are not anticipated from the Wapiti Trust and the Wapiti Trust is anticipated to be liquidated during 2013.

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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 Executive Officer is the 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 for each of the Recovery Trusts, subject to the terms of the respective trust agreements 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 March 25, 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 Plan provides that certain allowed general unsecured claims be paid with shares of our common stock. On the Emergence Date, 106 claims totaling approximately $73.7 million had been filed in the bankruptcy. Between the Emergence Date and December 31, 2012, the Recovery Trustee settled 25 claims with an aggregate face amount of approximately $6.6 million for $258,905 in cash and 202,773 shares of stock. Subsequent to year end and up to March 25, 2013, the Recovery Trustee settled an additional 25 claims with an aggregate face amount of approximately $12.3 million for $676,092 in cash and 1,469,575 shares of stock.

As of March 19, 2013, it is estimated that a total of 56 claims totaling approximately $54.8 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. Par believes 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. In addition, litigation and/or settlement efforts are ongoing with Macquarie Capital (USA) Inc., Swann and Buzzard Creek Royalty Trust, as well as other claim holders.

The settlement of claims is subject to ongoing litigation and we are unable to predict with certainty how many shares of our common stock will be required to satisfy all claims. Pursuant to the Plan, allowed claims are settled at a ratio of 544 shares per $1,000 of claim. At December 31, 2012, we have a reserve of approximately $8.7 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at year end. A summary of claims is as follows:

	Emergence-Date August 31, 2012				Year-ended December 31, 2012
	Filed Claims				Settled Claims								Remaining Filed Claims
									Consideration
	Count		Amount		Count		Amount		Cash		Stock		Count		Amount
U.S. Government Claims		3	$	22,364,000		—	$	—	$	—		—		3	$	22,364,000
Former Employee Claims		32		16,379,849		13		3,685,253		229,478		202,231		19		12,694,596
Macquarie Capital (USA) Inc.		1		8,671,865		—		—		—		—		1		8,671,865
Swann and Buzzard Creek Royalty Trust		1		3,200,000		—		—		—		—		1		3,200,000
Other Various Claims*		69		23,120,396		12		2,914,859		29,427		522		57		20,205,537
Total		106	$	73,736,110		25	$	6,600,112	$	258,905		202,753		81	$	67,135,998

	Subsequent to Year-ended December 31, 2012 through March 19, 2013
	Settled Claims								Remaining Filed Claims
					Consideration
	Count		Amount		Cash		Stock		Count		Amount
U.S. Government Claims		—	$	—	$	—		—		3	$	22,364,000
Former Employee Claims		12		11,750,904		278,338		1,361,452		7		943,692
Macquarie Capital (USA) Inc.		—		—		—		—		1		8,671,865
Swann and Buzzard Creek Royalty Trust		—		—		—		—		1		3,200,000
Other Various Claims*		13		581,607		397,754		108,123		44		19,623,930
Total		25	$	12,332,511	$	676,092		1,469,575		56	$	54,803,487

* Includes reserve for contingent/unliquidated claims in the amount of $10 million

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As of December 31, 2012, Texadian had various agreements to lease 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. Leases generally range in duration of five years or less and contain lease renewal options at fair value.

Contractual Obligations

Our asset retirement obligation arises from the costs necessary to plug and abandon our natural gas and oil wells. As of December 31, 2012, we had the following contractual debt obligations (see Note 6 of our accompanying consolidated financial statements for further discussion regarding the specific terms of our debt):

	Payment due by period
Contractual Obligations	Total		Less than 1 year (2013)		1-3 years (2014-2015)		3-5 years (2016-2017)		More than 5 years (after 2017)
Long-Term Debt—Principal	$	50,140,000	$	36,750,000	$	—	$	13,390,000	$	—
Long-Term Debt—Fixed Interest		7,421,647		3,101,793		3,134,146		1,185,708		—
Asset Retirement Obligations		1,324,502		132,356		264,712		264,712		662,722
Operating Lease Obligations		6,645,564		1,496,268		2,992,536		2,156,760		—
Total	$	65,531,713	$	41,480,417	$	6,391,394	$	16,997,180	$	662,722

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 and 3 to our 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, oil and gas reserves, bad debts, oil and natural gas 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.

Derivatives and Other Financial instruments

We may 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 future 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.

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.

Investments in unconsolidated affiliates

Investments in operating entities where we have the ability to exert significant influence, but do not control the operating and financial policies, are accounted for using the equity method. Our share of net income of these entities is recorded as income (losses) from unconsolidated affiliates in the consolidated statements of operations.

Property and equipment

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 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

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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 natural gas and oil 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) as the related proved, producing reserves are produced. Associated leasehold costs are depleted using the unit of production method based on total proved natural gas and oil reserves.

Other property and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives ranging from three to 15 years.

The application of the successful efforts method of accounting requires our judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within an natural gas and oil field are typically considered development costs and are capitalized, but often these seismic programs extend beyond the reserve area considered proved, and we must estimate the portion of the seismic costs to expense. The evaluation of natural gas and oil leasehold acquisition costs requires our judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding a natural gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

Reserve Estimates

Estimates of natural gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future natural gas and oil prices, the availability and cost of capital to develop the reserves, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our natural gas and oil properties and/or the rate of depletion of the natural gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Goodwill and Other Intangible Assets

We recorded goodwill as a result of our acquisition of Texadian. Goodwill is attributable to the synergies 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, as a result of our acquisition of Texadian, 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.

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Impairment of Goodwill and Long-Lived Assets

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. Qualitative factors assessed for the reporting unit would include the competitive environments and financial performance of the reporting unit. 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, based upon a multiple of estimated earnings. 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. The fair value calculation uses level 3 (see “Fair Value Measurements” below) inputs and includes multiple assumptions and estimates, including the projected cash flows and discount rates applied. Changes in these assumptions and estimates could result in goodwill impairment that could materially adversely impact our financial position or results of operations.

Long-lived assets are reviewed for impairment quarterly or when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

Estimates of expected future cash flows represent our best estimate based on reasonable and supportable assumptions and projections. For proved properties, if the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized are permanent and may not be restored in the future.

We assess proved properties on an individual field basis for impairment each quarter when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For proved properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs.

For unproved properties, the need for an impairment charge is based on our plans for future development and other activities impacting the life of the property and our ability to recover our investment. When we believe the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. For the period from September 1 through December 31, 2012, there were no impairments recorded by the Successor. At December 31, 2011, the Predecessor’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 to write-down these assets to fair value at that time. The Predecessor’s assets were further adjusted due to the application of fresh start accounting upon the Predecessor’s emergence from Chapter 11. The Predecessor recognized impairment expenses totaling approximately $151.3 million for the period January 1, 2012 through August 31, 2012 and $420.4 million for the year ended December 31, 2011, respectively.

Asset Retirement Obligation

We account for our asset retirement obligations under applicable FASB guidance which requires entities to record the fair value of a liability for retirement obligations of acquired assets. Our asset retirement obligations arise from the plugging and abandonment liabilities for our oil and gas wells. The fair value is estimated based on a variety of assumptions including discount and inflation rates and estimated costs and timing to plug and abandon wells.

Fair Value Measurements

We follow accounting guidance which defines fair value, establishes a framework for measuring fair value in U.S. GAAP, and requires additional disclosures about fair value measurements. As required, we applied the following fair value hierarchy:

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

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hierarchy levels. Our policy is to recognize transfer 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. These valuation policies are determined by our Chief Financial Officer and approved by our Chief Executive Officer. They are discussed with our Audit Committee as deemed appropriate. Each quarter, our Chief Financial Officer and Chief Executive Officer update the inputs used in the fair value measurement and internally review the changes from period to period for reasonableness. 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 Accounting – The fair value of the Successor was based on its estimated enterprise value post-bankruptcy using valuation techniques described in notes (a) through (f) described 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 have been reflected in the Successor’s consolidated balance sheet as of August 31, 2012.

	Fair Value at August 31, 2012		Fair Value Technique
	(in thousands)
Oil and gas properties
Proved	$	4,587		(a	)(b)
Other assets
Frac tanks	$	1,400		(c	)
Compressors		2,800		(d	)
Miscellaneous		39		(e	)
	$	4,239
Investment in Piceance Energy	$	105,344		(f	)

(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 was valued using a market valuation technique which was based on published listings of similar equipment. We consider this to be a level 2 fair value measurement.

(d) The estimated fair value of the compressor units was valued using a market valuation technique based on standalone bids received by third-parties. We consider this to be a level 2 fair value measurement.

(e) 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.

(f) The estimated fair value of our investment in Piceance Energy is 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. A change in significant inputs such a reduction in commodity pricing or an increase in discount rates would result in a lower fair value.

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 (e) described below.

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	Fair Value at December 31, 2012			Fair Value 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 shippers, 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.

Proved property impairments – The fair values of the proved properties are estimated using internal discounted cash flow calculations based upon the our estimates of reserves and are considered to be level 3 fair value measurements. This estimation is based on an independent reserve report with industry standard discounts applied to the reserves.

Asset retirement obligations – The initial fair values of the asset retirement obligations are estimated using the income valuation technique and internal discounted cash flow calculations based upon the our asset retirement obligations, including revisions of the estimated fair values during the period from September 1 through December 31, 2012, and are considered to be level 3 fair value measurements.

Assets and Liabilities Recorded at Fair Value on a Recurring Basis

Derivative liabilities associated with our debt agreement – Derivative liabilities include the Warrants and fair value is estimated using an income valuation technique and 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 the initial stock price of $0.70 per share, initial exercise price $0.01, term of 10 years, risk free rate of 1.6%, and expected volatility of 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 $0.69 per share at issuance or $6.6 million. 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. There was no material change in the inputs used to measure fair value or in the fair value as of December 31, 2012.

In addition, our Loan Agreement contains 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 consider 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 of approximately $65,000 at issuance 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

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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. There was no material change in the inputs used to measure fair value or in the fair value as of December 31, 2012.

Derivative instruments – With the acquisition of Texadian, we assumed certain open positions consisting of non-exchange traded fixed price future contracts and exchange traded commodity swap, options and futures contracts. The fair value of our commodity derivatives is measured using the closing market price at the end of the reporting period obtained from the NYMEX and from third party broker quotes and pricing providers.

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 consist of the following (in thousands):

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

	Location on Consolidated Balance Sheet		Fair Value at December 31, 2012
			(in thousands)
Commodities – physical forward contracts		Prepaid and other current assets	$	(307	)
Commodities – exchange traded futures		Prepaid and other current assets	$	542
Warrant derivatives		Noncurrent liabilities	$	(10,900	)
Embedded derivative		Noncurrent liabilities	$	(45	)

A rollforward of Level 3 derivative warrants and the embedded derivative measured at fair value using level 3 on a recurring basis is as follows (in thousands):

Description
Balance, at September 1, 2012	$	(6,665	)
Purchases, issuances, and settlements		—
Total unrealized losses included in earnings		(4,280	)
Transfers		—
Balance, at December 31, 2012	$	(10,945	)

The estimated fair value and notional amounts of Texadian’s open physical forward commodity contracts are shown in the table below (in thousands except volumes):

	Open Physical Forward Contracts
	December 31, 2012
				Notional Amounts
	Fair Value			Value		Volumes		Volume Unit		Maturity Dates
Crude oil	$	(227	)	WTI plus $	3.00		60,000		barrels		January 2013
Crude oil	$	(80	)	WTI plus $	15.00		21,467		barrels		January 2013

Income Taxes

Pursuant to the Plan, on the Emergence Date, the existing equity interests of the Company 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

46

before the change that may be used to offset taxable income after the ownership change. The Company believes however that it 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 the Company’s net operating losses; however the net operating losses are eliminated should another ownership change occur within two years. The amended and restated certificate of incorporation of the Company place restrictions upon the ability of the equity interest holders to transfer their ownership in the Company. These restrictions are designed to provide the Company with the maximum assurance that another ownership change does not occur that could adversely impact the Company’s 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 continues to conclude that the Company does 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 Company’s net deferred tax assets at December 31, 2012.

As of December 31, 2012, our deferred tax assets exceeded deferred tax liabilities. Accordingly, based on significant recent operating losses other than the non-recurring taxable income resulting from the Contribution Agreement, and projections for future results, a valuation allowance has been recorded for the Company’s net deferred tax assets.

The Company will continue to assess the realizability of its deferred tax assets on a go forward basis taking into account 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.

During the periods from January 1 through August 31, 2012 and during the period from September 1 through December 31, 2012, and for the year ended December 31, 2011, no adjustments were recognized for uncertain tax benefits.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Rate and Price Risk

Revenues from our natural gas and oil business are derived from the sale of our natural gas and oil production. Based on projected annual sales volumes for 2013, a 10% decline in the estimated average prices we expect to receive for our natural gas and oil production would have an approximate $0.7 million impact on our 2013 revenues.

Texadian enters and settles positions in various exchange traded commodity swap and future contracts. Texadian also enters into exchange traded positions to protect its inventory balances from market changes. As of December 31, 2012, Texadian had exited the ethanol business, held no physical ethanol inventory and there was no market exposure to ethanol other than its ethanol futures contracts due through February 2013. In Texadian’s commodity marketing and logistics business, fixed price future purchase and sale contracts of crude oil are included in the calculation of Texadian’s non-exchange traded derivative positions. The gain or loss of these non-exchange traded physical contracts is calculated based on the difference between current market prices and the contractually obligated price, which can be either fixed or become fixed due to delayed or accelerated delivery. The settlement of these non-exchange derivative positions does not result in a cash settlement but instead an adjustment to either sales or cost of sales to fair value with an offsetting entry to derivatives gain or loss. As of December 31, 2012, the fair value of these exchange and non-exchange commodity contracts was an asset of approximately $0.2 million, net.

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

Not applicable.

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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, 2012, 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. 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 as of December 31, 2012, these disclosure controls and procedures were not effective and not designed to ensure that the information required to be disclosed in our reports filed with the SEC is recorded, processed, summarized and reported on a timely basis. 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, as such term is defined in Exchange Act Rule 15d-15(f). 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, 2012.

Prior to December 31, 2011, the Company filed for voluntary bankruptcy and during the duration of the proceedings, the Company’s the ability to maintain effect internal control over financial reporting was weakened due to a high amount of turnover of its accounting staff. Because of the high turnover and low number of accounting personnel available, the Company was not able to timely file its Form 10-K as of December 31, 2011. Management of the Company concluded that internal control over financial reporting as of December 31, 2011 was not effective. As of August 31, 2012, the Company emerged from bankruptcy and replaced the operations and financial reporting functions with a new accounting group. During the fourth quarter of 2012, management of the Company performed a comprehensive assessment of the design and operating effectiveness of internal control over financial reporting. While performing the review of the design and operating effectiveness of our internal control over final reporting, control gaps were identified in internal control and related processes that require remediation to be performed in order for management to conclude that internal control over final reporting is effective in preventing the financial statements and related disclosures from being materially misstated. The internal control gap remediation to be performed by management was not completed as of December 31, 2012. Additionally, while completing our December 31, 2012 year end close process, adjustments were identified relating to the application of fresh start accounting that impacted the amounts, presentation of the financial statements and related disclosures previously reported at September 30, 2012 in our From 10-Q. Because of the items mentioned above, management has concluded that a material weakness exists in the operating effectiveness of internal control over financial report.

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.

Changes in Internal Controls over Financial Reporting

There have been no changes during the Company’s quarter ended December 31, 2012, in the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financing reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors and Executive Officers and Corporate Governance

Executive Officers and Directors

Our current executive officers and members of our Board, and their respective ages, are as follows:

Name	Age	Position
William Monteleone (2) (3)	29	Chairman of the Board of Directors(4)
Jacob Mercer(2) (3)	37	Director
Benjamin Lurie(2)	30	Director
Michael R. Keener(1)	53	Director
L. Melvin Cooper(1)	59	Director
John T. Young, Jr.	39	Chief Executive Officer
R. Seth Bullock	39	Chief Financial Officer

(1) Member of the Audit Committee.

(2) Member of the Compensation Committee.

(3) Member of the Strategic and Operations Committee.

(4) Mr. Monteleone was appointed to serve as Chairman from March 1, 2013 to August 31, 2013. It is anticipated that the Chairman will be voted on by the Board starting September 1, 2013.

William Monteleone, age 29, has served as a director since August 2012. Mr. Monteleone is an Associate at Equity Group Investments (“EGI”) having joined in 2008. Previously, Mr. Monteleone worked for Banc of America Securities LLC from 2006 to 2008 where he was involved in a variety of debt capital raising transactions, including leveraged buyouts, corporate-to-corporate acquisitions and other debt financing activities. At EGI, he is responsible for evaluating potential new investments and monitoring existing investments. In addition to our Board, Mr. Monteleone serves on the Board of Directors of Wapiti Oil and Gas, LLC and Kuwait Energy Company. Mr. Monteleone graduated magna cum laude from Vanderbilt University with a bachelor’s degree.

Jacob Mercer, age 37, has served as a director since August 2012. Mr. Mercer joined Whitebox in October 2007 and is a Senior Portfolio Manager focusing on distressed and high yield investments. Previously, Mr. Mercer worked for Xcel Energy (XEL) from July 2005 to October 2007 as Assistant Treasurer and Managing Director. Prior to that, he worked at Piper Jaffray as a Senior Credit Analyst and Principal and at Voyageur Asset Management as a Credit Analyst. In addition, Mr. Mercer served as a Logistics Officer in the United States Army. Mr. Mercer holds a BA in both Business Management and Economics from St. John’s University. He holds the Chartered Financial Analyst designation. Mr. Mercer also serves on the Board of Directors for the following privately held companies: ES Purchaser LLC, since January 2012, and Sunshine Enterprises Ltd., since November 2011.

Benjamin Lurie, age 30, has served as a director since August 2012. Mr. Lurie is an Associate at EGI having joined in 2011. Prior to joining the firm in 2011, Mr. Lurie worked at Lurie Investments evaluating and developing new and existing business opportunities ranging from technology to services to real estate from January 2006 to December 2010. At EGI, Mr. Lurie is responsible for evaluating potential new investments and monitoring existing investments. He holds a master’s degree in business administration from INSEAD, and a postgraduate certificate from the United Nations University. He received dual bachelor’s degrees from the University of Wisconsin-Madison. He holds the Charted Financial Analyst designation.

Michael Keener, age 53, has served as a director since August 2012. Mr. Keener has over 30 years of experience in the energy sector. Since January 2011, Mr. Keener has served as a Principal of KP Energy, providing mezzanine debt, private equity and direct asset ownership primarily with exploration and production companies in North America. Prior to joining KP Energy, Mr. Keener worked as a Managing Director in the energy team of Imperial Capital LLC from October 2009 until December 2010. From February 2003 until their acquisition by Imperial Capital in October 2009, Mr. Keener served as Principal and Managing Director of Petrobridge Investment Management, LLC. From 1981 to 2003, Mr. Keener served in a number of roles in Royal Dutch Shell PLC including as Director and Vice President of Shell Capital and Financial Advisor to Shell Offshore. Mr. Keener also has served on the Board of Directors of Dune Energy (OTC Bulletin Board: DUNR) since January 2012. Mr. Keener holds a degree in Business Administration from Bloomsburg University and a Masters of Business Administration from Loyola University. Mr. Keener has extensive financial and operating experience, and his background, prior experiences, professional credentials and expertise qualify him to serve as one of our Audit Committee financial experts and a director.

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L. Melvin Cooper, age 59, has served as a director since August 2012. Mr. Cooper has been a Director of the Board, a member of the Audit Committee and a member of the Corporate Governance and Nominating Committee since October 2010, and has been a member of the Compensation Committee since 2011. Currently, Mr. Cooper serves as the Senior Vice President and Chief Financial Officer of Forbes Energy Services Ltd. (NASDAQ Global Market: FES), a public company in the energy services industry. Prior to joining Forbes in 2007, Mr. Cooper served as Senior Vice President and Chief Financial Officer of Cude Oilfield Contractors, Inc., beginning in 2007. From 2004 to 2007, Mr. Cooper served as President of SpectraSource Corporation, a supplier of products and services to the new home building industry. From 2000 to 2004, Mr. Cooper served as President of Cerqa, the supply chain management division of Nationwide Graphics, Inc., a national printing and supply chain management company where Mr. Cooper formerly served as Senior Vice President and Chief Financial Officer. Mr. Cooper has also served as President or CFO of various companies involved in telecommunications, nutritional supplements, water purification, scrap metal, drilling fluids, and natural gas marketing. Mr. Cooper is a member of the Board of Directors and is the Audit Committee Chairman for Par Petroleum Corporation, where has served since October 2012. In 2011, Mr. Cooper received the Board Leadership Fellow designation from the National Association of Corporate Directors (“NACD”) where he is also a member of the Board of Directors of the NACD Houston area Tri-City Chapter. Mr. Cooper earned a degree in accounting from Texas A&M University-Kingsville (formerly Texas A&I) in 1975. Mr. Cooper has been a Certified Public Accountant since May 1977. Mr. Cooper’s extensive experience in the energy industry as well as his financial background brings significant additional operating, financial and management experience to the Board.

John T. Young, Jr., age 39, has served as our Chief Executive Officer since August 2012. We previously appointed Mr. Young as our Chief Restructuring Officer in November 2011, and appointed him as Chief Financial Officer in July 2012. Mr. Young also currently serves as Senior Managing Director at Conway MacKenzie, Inc., which we retained in late 2011 to assist with our strategic alternatives process. Mr. Young has served as Senior Managing Director at Conway MacKenzie, Inc. since December 2008. Mr. Young has substantial knowledge and experience providing restructuring advisory services, including interim management and debtor advisory, litigation support, post-merger integration and debt restructuring and refinancing. Mr. Young’s experience also includes serving in a multitude of advisory capacities within the energy and oilfield services industries as well as Lone Star Funds and KPMG Peat Marwick. Mr. Young is a Certified Public Accountant and received his BBA and MBA from Baylor University.

R. Seth Bullock, age 39, has served as our Chief Financial Officer since August 2012. Mr. Bullock previously served as our Treasurer from July 2012 through August 2012. He serves as a Managing Director at Conway MacKenzie, Inc. and has been employed with Conway MacKenzie, Inc. since November 2011. From May 2010 through November 2011, Mr. Bullock served as Managing Director at Kenmont Solutions Capital, a direct origination mezzanine fund focused on middle market companies in the energy, power and infrastructure sectors. From July 2007 through May 2010, Mr. Bullock served as Analyst at Kenmont Investments Management, a multi-strategy hedge fund focused on the energy, power and transportation sectors. Prior to Kenmont, Mr. Bullock held positions of increasing responsibility with Koch Capital Markets, a division of Koch Industries, Inc. Prior to Koch, Mr. Bullock held positions of increasing responsibility with Arthur Andersen’s Global Energy Corporate Finance Group. Mr. Bullock holds a BBA in Finance from Loyola University, New Orleans. He holds the Chartered Financial Analyst designation.

Code of Ethics

The Board has adopted a code of business conduct and ethics. The code applies to all of our employees, officers (including our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions), directors and consultants. The full text of our code of business conduct and ethics is posted on our website at http://www.par-petro.com/Governance_Documents. We expect that any amendments to the code, or any waivers of its requirements, will be disclosed on our website.

Corporate Governance

The Board is composed of five members. Under our stockholders agreement dated effective August 31, 2012 (the “Stockholders Agreement”), certain of our stockholders have the right to elect members of the Board.

Whitebox and its affiliates may designate two individuals in the two-year period following the Emergence Date, and after such two-year period, Whitebox may designate two (2) individuals so long as Whitebox or its affiliates hold at least ten percent (10%) of the outstanding shares of our common stock and one (1) individual so long as Whitebox or its affiliates hold at least five percent (5%) but less than ten percent (10%) of the outstanding shares of our common stock (collectively, the “Whitebox Designees”). In the event that Whitebox or its affiliates no longer hold at least five percent (5%) of the outstanding shares of our common stock, the Whitebox Designees shall be designated by holders of a majority of the outstanding shares of our common stock.

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ZCOF and its affiliates may designate two individuals designated by ZCOF in the two-year period following the Emergence Date, and after such two-year period, ZCOF may designate two (2) individuals so long as ZCOF or its affiliates hold at least ten percent (10%) of the outstanding shares of our common stock and one (1) individual so long as ZCOF or its affiliates hold at least five percent (5%) but less than ten percent (10%) of the outstanding shares of our common stock (collectively, the “ZCOF Designees”). In the event that ZCOF or its affiliates no longer hold at least five percent (5%) of the outstanding shares of our common stock, the ZCOF Designees shall be designated by holders of a majority of the outstanding shares of our common stock.

One individual (the “Independent Designee”) shall be designated jointly by Whitebox, ZCOF and Waterstone, so long as Whitebox, ZCOF and Waterstone and/or their affiliates collectively hold at least twenty percent (20%) of the outstanding shares of our common stock, which Independent Designee shall not be an affiliate of Whitebox, ZCOF or Waterstone. In the event that Whitebox, ZCOF and Waterstone are no longer collectively holders of at least twenty percent (20%) of the outstanding shares of our common stock, then the Independent Designee shall be designated by holders of a majority of the then outstanding shares of our common stock. In addition, in the event that any of Whitebox, ZCOF or Waterstone (together with its affiliates) individually no longer holds at least five percent (5%) of the shares of our common stock, then such person shall no longer be entitled to jointly designate the Independent Designee, which Independent Designee shall thereafter be designated by the remaining persons who are still entitled to appoint the Independent Designee.

To the extent that any of the above as to Whitebox, ZCOF or Waterstone shall not be applicable, any member of the Board who would otherwise have been designated in accordance with the terms thereof shall instead be voted upon by all of our stockholders entitled to vote thereon in accordance with our certificate of incorporation.

Messrs. Monteleone and Lurie are the ZCOF Designees, Messrs. Mercer and Cooper are the Whitebox Designees and Mr. Keener is the Independent Designee.

The Board has established the Audit, Compensation, and Strategic and Operations Committees as its standing committees. Prior to the Emergence Date, the members of the Audit Committee were former Board members Kevin R. Collins, Jerrie F. Eckelberger, Jordan R. Smith and Daniel J. Taylor. Each of those directors departed the Board as of the Emergence Date. As of the Emergence Date, and for the remainder of 2012, the members of the Audit Committee were Messrs. Keener and Cooper. The Board has determined that Messrs. Keener and Cooper are both audit committee financial experts under Item 407(d) of Regulation S-K of the SEC. Under applicable rules promulgated by the SEC and The NASDAQ Stock Market listing standards (although our common stock is no longer listed on NASDAQ), all of the members of the Audit Committee were and are independent.

Our bylaws contain provisions that address the process by which a stockholder may nominate an individual to stand for election to the Board at our Annual Meeting of Stockholders. We do not have a formal policy concerning stockholder nominations of individuals to stand for election to the Board, other than the provisions contained in our bylaws. To date, we have not received any recommendations from stockholders requesting that the Board consider a candidate for inclusion among the slate of nominees in any year, and therefore we believe that no formal policy, in addition to the provisions contained in our bylaws, concerning stockholder recommendations is needed.

Our bylaws provide that nominations for the election of directors may be made by any stockholder entitled to vote in the election of directors. To be timely, a stockholder’s notice must be delivered to or mailed and received at our principal executive offices not less than ninety days nor more than one hundred twenty days prior to the date of the meeting; provided, however, that in the event that public disclosure of the date of the meeting is first made less than one hundred days prior to the date of the meeting, notice by the stockholder in order to be timely must be so received not later than the close of business on the tenth day following the day on which such public disclosure of the date of the meeting was made. To be in proper written form, a stockholder’s notice regarding nominations of persons for election to the Board must set forth (a) as to each proposed nominee, (i) the name, age, business address and residence address of the nominee, (ii) the principal occupation or employment of the nominee, (iii) the class or series and number of shares of our capital stock which are owned beneficially or of record by the nominee and (iv) any other information relating to the nominee that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Exchange Act, and the rules and regulations promulgated thereunder; and (b) as to the stockholder giving the notice, (i) the name and record address of such stockholder, (ii) the class or series and number of shares of our capital stock which are owned beneficially or of record by such stockholder, (iii) a description of all arrangements or understandings between such stockholder and each proposed nominee and any other person or persons (including their names) pursuant to which the nomination(s) are to be made by such stockholder, (iv) a representation that such stockholder intends to appear in person or by proxy at the meeting to nominate the persons named in its notice and (v) any other information relating to such stockholder that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Exchange Act and the rules and regulations promulgated thereunder. Such notice must be accompanied by a written consent of each proposed nominee to being named as a nominee and to serve as a director if elected.

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Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our executive officers, directors and persons who beneficially own more than ten percent (10%) of a registered class of our equity securities, to file initial reports of ownership of our securities and reports of changes in ownership of our securities with the SEC.

Based solely on a review of the copies of such reports furnished to us by our officers, directors, and persons who beneficially own more than ten percent (10%) of our common stock, and their written representations that such reports accurately reflect all reportable transactions, there were no late filings for fiscal year 2012.

Item 11. Executive Compensation

Compensation Discussion and Analysis

In connection with our emergence from bankruptcy on August 31, 2012, and pursuant to the Plan, John T. Young, Jr. was engaged as our Chief Executive Officer and R. Seth Bullock was engaged as our Chief Financial Officer. Messrs. Young and Bullock are our only executive officers and are also employees of Conway McKenzie Management Services, LLC (“Conway McKenzie”), with whom we have a management and financial advisory services agreement dated November 8, 2011. As a result, we do not currently have any executive officers which are directly employed by us.

The current members of the Compensation Committee of the Board did not serve on the Compensation Committee prior to our emergence from bankruptcy on the Emergence Date. Pursuant to the charter of the Compensation Committee adopted subsequent to our emergence from bankruptcy, it is the duty of the Compensation Committee to, among other things, develop and approve our compensation philosophy and objectives, review and determine the amount and mix of total compensation of our executive officers, develop, administer and review our employment agreements, incentive plans and other compensation programs, and oversee the risk assessment of our compensation arrangements.

Until we are in a position to directly engage individuals to serve as executive officers, we expect to continue to use the services of Conway McKenzie, including the services of Messrs. Young and Bullock. As a result, we do not currently have a specific compensation philosophy, or specific compensation objectives or policies. We also do not expect to have any employment agreements or other similar arrangement in place until we directly engage individuals to serve as executive officers.

Compensation Committee Report

The Compensation Committee of the Board has reviewed and discussed the Compensation Discussion and Analysis with management. Based upon such review and discussion, and such other matters deemed relevant and appropriate by the Compensation Committee, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

Respectfully submitted by the Compensation Committee of the Board of Directors:

Jacob Mercer (Chairman)

William Monteleone

Benjamin Lurie

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Summary Compensation

The following table sets forth information regarding compensation earned during the last three fiscal years by our Chief Executive Officer, our Chief Financial Officer, our former Chief Executive Officer, our former Chief Financial Officers and our former General Counsel and Secretary, our only other executive officers during 2012 (the “Named Executive Officers”).

SUMMARY COMPENSATION TABLE

Name and Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards ($)(1)		Non-Equity Incentive Plan Compensation ($)(2)		All Other Compensation (3) ($)		Total ($)
John T. Young, Jr.—Chief Executive Officer and		2012		—		—		—		—		—		—
Former Chief Financial Officer (4)		2011		—		—		—		—		—		—
R. Seth Bullock—Chief Financial Officer and		2012		—		—		—		—		—		—
Former Treasurer (5)		2011		—		—		—		—		—		—
Carl E. Lakey—Former President and Chief		2012		273,959		—		—		364,774		25,543		664,276
Executive Officer (6)		2011		398,970		—		660,000		329,162		30,744		1,418,876
		2010		338,585		—		700,000		480,500		19,768		1,538,853
Kevin K. Nanke—Former Treasurer and Chief		2012		205,573		—		—		212,412		38,918		456,903
Financial Officer (7)		2011		337,144		—		560,000		182,311		26,350		968,115
		2010		328,600		—		793,637		395,000		25,339		1,308,939
Stanley F. Freedman—Former Executive Vice		2012		155,964		—		—		189,170		418,761		763,896
President, General Counsel and Secretary (8)		2011		300,245		—		264,000		162,358		29,436		756,039
		2010		293,750		—		490,000		323,500		21,259		1,128,509

(1) These amounts shown represent the aggregate grant date fair value for stock awards granted to the Named Executive Officers computed in accordance with FASB ASC Topic 718. Assumptions used in the calculation of these amounts are included in “Note 10 – Stockholders’ Equity” to our audited financial statements for the fiscal year ended December 31, 2012 included in this Annual Report on Form 10-K. All outstanding stock awards were cancelled as of the Emergence Date.

(2) The amounts reflect cash bonus awards to the Named Executive Officers. Awards under our bonus plans were accrued and earned in the year represented and paid in the following year. All of our bonus plans were cancelled as of the Emergence Date.

(3) Amounts in the “All Other Compensation” column consist of the following payments we paid to or on behalf of the Named Executive Officers:

			Company				Auto				Consulting
			Contributions to		Auto		Maintenance		Health		Agreement
			Retirement Plans		Allowance		and Insurance		Club		Payments			Claim Settlement Amount			Total
Name	Year		($)		($)		($)		($)		($)			($)			($)
John T. Young, Jr.		2012		—		—		—		—		—			—			—
R. Seth Bullock		2012		—		—		—		—		—			—			—
Carl E. Lakey		2012		11,250		13,200		1,093		—		—			—			25,543
		2011		8,977		19,800		1,967		—		—			—			30,744
		2010		5,961		9,000		4,807		—		—			—			19,768
Kevin K. Nanke		2012		11,250		11,550		2,218		1,400		12,500	(a)		—			38,918
		2011		—		19,800		4,150		2,400		—			—			26,350
		2010		—		18,000		4,939		2,400		—			—			25,339
Stanley F. Freedman		2012		10,785		9,900		1,327		—		25,000	(a)		371,749	(b)		418,761
		2011		6,756		19,800		—		2,880		—			—			29,436
		2010		—		18,000		3,259		—		—			—			21,259

(a) The terms of the consulting agreements with Messrs. Nanke and Freedman are described below under “– Employment Agreements.”

(b) Represents the negotiated value of 202,232 shares of our common stock issued to Mr. Freedman in settlement of his claim for compensation with the Bankruptcy Court.

(4) During 2011 and 2012 prior to July 19, 2012, Mr. Young served as our Chief Restructuring Officer pursuant to our agreement with Conway McKenzie as described in “-Compensation Discussion and Analysis”. Mr. Young was appointed as our Chief Financial Officer on July 19, 2012 and then as our Chief Executive Officer effective August 31, 2012 pursuant to the Plan. We pay Conway McKenzie for the services provided by Mr. Young as described in “-Compensation Discussion and Analysis”, and as such, he does not receive any salary or other compensation from us.

(5) During 2011 and 2012 prior to the Emergence Date, Mr. Bullock served as one of our Restructuring Managers pursuant to our agreement with Conway McKenzie as described in “-Compensation Discussion and Analysis”. Mr. Bullock was appointed as our Treasurer on July 19, 2012 and then as our Chief Financial Officer effective August 31, 2012 pursuant to the Plan. We pay Conway McKenzie for the services provided by Mr. Bullock as described in “-Compensation Discussion and Analysis”, and as such, he does not receive any salary or other compensation from us.

(6) Mr. Lakey’s service with us ceased on the Emergence Date.

(7) Mr. Nanke’s service with us ceased on the Emergence Date.

(8) Mr. Freedman’s service with us ceased on the Emergence Date.

Narrative Disclosure to Summary Compensation Table

See “– Employment Agreements” and”– Potential Payments upon Termination or Change in Control” below for a discussion of the prior employment agreements and severance agreements with certain of our Named Executive Officers. See “– Compensation Discussion and Analysis” for an explanation of how our current executive officers are compensated and why we do not currently have specific compensation objectives or a compensation philosophy. See the footnotes to the Summary Compensation Table for narrative disclosure with respect to that table.

Grants of Plan-Based Awards

There were no grants of plan-based awards during 2012 to the Named Executive Officers.

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Outstanding Equity Awards at Fiscal Year-End

There were no outstanding equity awards held by the Named Executive Officers at year end 2012.

Option Exercises and Stock Vested

There were no option award exercises or stock awards vestings during 2012.

Employment Agreements

We were party to employments agreements with each of Messrs. Lakey, Nanke and Freedman prior to the cessation of their employment with us in 2012. Those agreements were terminated in connection with their cessation of employment. Each of Messrs. Nanke and Freedman entered into consulting agreements with us after the cessation of their employment with us in order to provide assistance to us as we completed the bankruptcy process. These agreements were terminated as of the Emergence Date. Pursuant to the agreements, Messrs. Nanke and Freedman received $12,500 per month for up to 80 hours of work during such month and $550 per hour for each additional hour in excess of 80 hours, up to a cap of $25,000 per month.

None of our current Named Executive Officers is party to an employment agreement with us.

Potential Payments upon Termination or Change in Control

We were party to Change-In Control Executive Severance Agreements with each of Messrs. Lakey, Nanke and Freedman in 2012 prior to the cessation of their employment with us. Those agreements were terminated in connection with their cessation of their employment. As none of those individuals received any amount pursuant to those agreements in connection with their separation, Messrs. Lakey, Nanke and Freedman filed non-priority, general unsecured claims against us in the bankruptcy for $2,294,876, $2,030,876, and $2,988,117, respectively. As described in the “All Other Compensation” column of the Summary Compensation Table, we have settled with Mr. Freedman by issuing him shares of our common stock valued at approximately $371,749 (as specified in the order of the Bankruptcy Court dated November 16, 2012). The claims of Messrs. Lakey and Nanke are still pending with the Bankruptcy Court.

None of our current Named Executive Officers is entitled to any payments upon their termination or upon a change in control.

Director Compensation

The following table sets forth a summary of the compensation we paid to our non-employee directors in 2012:

	Fees Earned or Paid in Cash		Stock Awards			Total
Name	($)		($)(1)			($)
Jacob Mercer (2)		—		—			—
William Monteleone (2)		—		41,780	(5),(6)		41,780
Benjamin Lurie (2)		—		41,780	(5),(6)		41,780
Michael Keener (2)		18,383		25,068	(5)		43,451
L. Melvin Cooper (2)		21,726		25,068	(5)		46,794
Anthony Mandekic (3)		20,083		—			20,083
Jen-Michel Fonck(3)		20,083		—			20,083
Kevin R. Collins (4)		98,833		—			98,833
Jerrie F. Eckelberger (4)		88,333		—			88,333
Jordan R. Smith (4)		80,500		—			80,500
Daniel J. Taylor (4)		177,375		—			177,375

(1) These amounts reflect the aggregate grant date fair value, calculated in accordance with FASB ASC Topic 718, of awards pursuant to the Incentive Plan. Assumptions used in the calculation of these amounts are included in “Note 6– Stockholders’ Equity” to our audited financial statements for the fiscal year ended December 31, 2012 included in this Annual Report on Form 10-K.

(2) Pursuant to the Plan, on the Emergence Date, each of these individuals became a director.

(3) Mssrs. Mandekic and Fonck resigned effective February 2, 2012 and February 12, 2012, respectively.

(4) Pursuant to the Plan, on the Emergence Date, each of these individuals departed the Board.

(5) Each of our directors received an award of 22,892 shares of common stock as of December 31, 2012 for their service in 2012, but prorated from the Emergence Date. The shares vest on the first anniversary of the date of grant.

(6) Messrs. Monteleone and Lurie elected to receive their annual retainer in shares of common stock, rather than cash, and as such, an additional 15,262 shares of common stock were issued to each of them on December 31, 2012.

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Prior to the Emergence Date, each non-employee director received an annual retainer of $50,000, paid on a monthly basis. Each Board committee chair also received an additional retainer each year in the following amounts: chair of the Audit Committee and chair of the Compensation Committee, $10,000; and chair of the Nominating and Corporate Governance Committee, $5,000. In addition, each non-employee director who was not a chairman but served on one or more committees of the Board received an annual retainer of $2,500. The additional retainer amounts were also paid to the directors in cash in equal monthly installments. We also reimbursed the directors for costs incurred by them in traveling to Board and committee meetings. During 2012, we also had a Restructuring Committee, which advised us on the bankruptcy process, among other things, and which was dissolved on the Emergence Date. Restructuring Committee members received $1,500 for each meeting attended. In addition, at the discretion of the Board, each non-employee director was eligible to receive an annual grant of shares of common stock. No shares were issued to non-employee directors in 2012 prior to the Emergence Date.

In December 2012, we approved a new compensation plan for our directors. Our directors receive an annual retainer of $50,000, 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 $15,000 and the members of the Audit Committee (other than the Chairman) receive an annual retainer of $5,000, 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 $75,000, with the number of shares determined by the 60-day volume weighted average share price as of the day prior to the grant date. Mr. Mercer waived his right to receive any of the compensation described in this paragraph in 2012. Each of our other directors received an award of 22,892 shares of common stock as of December 31, 2012 for their service in 2012, but prorated from the Emergence Date. Messrs. Monteleone and Lurie elected to receive their annual retainer in shares of common stock, rather than cash, and as such, an additional 15,262 shares of common stock were issued to each of them in December 2012.

Compensation Committee Interlocks and Insider Participation

No member of the Compensation Committee has ever been an officer of us or any of our subsidiaries, and none of our employees served on the Compensation Committee during the last fiscal year. We do not have any interlocking relationships between our executive officers and the compensation committee and the executive officers and compensation committee of any other entities, nor has any such interlocking relationship existed in the most recently completed fiscal year.

Narrative Disclosure of Compensation Policies and Practices as Related to Risk Management

In accordance with the requirements of Regulation S-K, Item 402(s), to the extent that risks may arise from our compensation policies and practices that are reasonably likely to have a material adverse effect on us, we are required to discuss those policies and practices for compensating our employees (including employees that are not named executive officers) as they relate to our risk management practices and the possibility of incentivizing risk-taking. We have determined that the compensation policies and practices established with respect to our employees are not reasonably likely to have a material adverse effect on us and, therefore, no such disclosure is necessary.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth certain information regarding the beneficial ownership of common stock as of March 25, 2013 of (i) each person who is known by us to own beneficially more than five percent of our outstanding shares of common stock, (ii) each Named Executive Officer, (iii) each of our directors and (iv) all of our directors and executive officers as a group. Unless otherwise noted, the mailing address of each person or entity named below who is known by us to beneficially own more than five percent (5%) of our outstanding shares of common stock is 1301 McKinney, Suite 2025, Houston, Texas 77010.

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Beneficial holders	Amount and Nature of Beneficial Ownership(1)
	Number		Percentage
5% Stockholders:
Zell Credit Opportunities Master Fund, L.P. (2)		56,359,319		36.6	%
Whitebox Advisors, LLC(3)		41,851,025		27.3	%
Waterstone Capital Management, L.P. (4)		29,021,800		19.1	%
Directors and Named Executive Officers:
Jacob Mercer		70,125		—
William Monteleone		38,154		—
Benjamin Lurie		38,154		—
Michael R. Keener		22,892		—
L. Melvin Cooper		22,892		—
John T. Young, Jr.		0		—
R. Seth Bullock		0		—
Carl E. Lakey (5)		0		—
Kevin K. Nanke (6)		0		—
Stanley F. Freedman (7)		202,232		—
All directors and executive officers as a group (7) persons)		192,217		—

* Denotes less than 1% beneficially owned.

(1) Based on 150,080,045 shares outstanding as of March 25, 2013.

(2) Information based solely upon the Schedule 13D jointly filed with the SEC on September 10, 2012 by ZCOF, Chai Trust Company, LLC and ZCOF Par Petroleum Holdings, L.L.C. Includes 3,959,328 shares of common stock issuable upon exercise of a warrant issued to ZCOF Par Petroleum Holdings, L.L.C. ZCOF and Chai Trust Company, LLC share voting and dispositive power over all of the shares. The address of these entities is Two North Riverside Plaza, Suite 600, Chicago, Illinois 60606.

(3) Information based solely upon the Schedule 13D jointly filed with the SEC on February 28, 2013 by Whitebox, Whitebox Asymetric Advisors, LLC, Whitebox Multi-Strategy Advisors, LLC, Whitebox Credit Arbitrage Advisors, LLC, Whitebox Concentrated Convertible Arbitrage Advisors, LLC, Pandora Select Advisors, LLC, Whitebox Asymmetric Partners, L.P., Whitebox Asymmetric Opportunities Fund, L.P., Whitebox Asymmetric Opportunities Fund, Ltd., Whitebox Multi-Strategy Partners, L.P., Whitebox Multi-Strategy Fund, L.P., Whitebox Multi-Strategy Fund, Ltd., Whitebox Credit Arbitrage Partners, L.P., Whitebox Credit Arbitrage Fund, L.P., Whitebox Credit Arbitrage Partners, L.P., Whitebox Credit Arbitrage Fund, L.P., Whitebox Credit Arbitrage Fund, Ltd., Whitebox Concentrated Convertible Arbitrage Partners, L.P., Whitebox Concentrated Convertible Arbitrage Fund, L.P., Whitebox Concentrated Convertible Arbitrage Fund, Ltd., Pandora Select Partners, L.P., Pandora Select Fund, L.P., Pandora Select Fund, Ltd., HFR RVA Combined Master Trust and IAM Mini-Fund 14 Limited. Includes 3,326,574 shares of common stock issuable upon exercise of a warrant issued to WB Delta, LTD. The address of Whitebox is 3033 Excelsior Blvd., Minneapolis, MN 55416.

(4) This information is based solely on the Schedule 13G jointly filed with the SEC on February 13, 2013 by Waterstone, Waterstone Market Neutral Master Fund, Ltd., Waterstone Capital Offshore Advisors, LP, Waterstone Asset Management, LLC and Shawn Bergerson. Waterstone, Waterstone Capital Offshore Advisors, LP, Waterstone Asset Management, LLC and Shawn Bergerson reported shared voting and dispositive power over the 25,584,808 shares beneficially owned, while Waterstone Market Neutral Master Fund, Ltd. Reported shared voting and dispositive power over 17,841,378 shares. Includes 1,797,210 shares of common stock issuable upon exercise of warrants issued to Waterstone Offshore ER Fund, LTD (197,278), Prime Capital Master SPC (29,736), Waterstone Market Neutral Mac51, LTD (109,030), Waterstone Market Neutral Master Fund, LTD (1,167,007), Waterstone MF Fund, LTD (272,097) and Nomura Waterstone Market Neutral Fund (22,062). The address of Waterstone, Waterstone Capital Offshore Advisors, LP, Waterstone Asset Management, LLC and Mr. Bergerson is 2 Carlson Parkway, Suite 260, Plymouth, Minnesota 55447. The address of Waterstone Market Neutral Master Fund, Ltd. is 45 Market Street, Suite 3205, 2nd Floor, Gardenia Court, Camana Bay, Grand Cayman KY1-9003, Cayman Islands.

(5) Mr. Lakey’s service with us ceased on the Emergence Date.

(6) Mr. Nanke’s service with us ceased on the Emergence Date.

(7) Mr. Freedman’s service with us ceased on the Emergence Date.

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Plan Information

Our sole equity-based compensation is the Incentive Plan, which has been approved by the Board, but not yet approved by our stockholders. See “Note 10 – Stockholders’ Equity” to our consolidated financial statements included in this Annual Report on Form 10-K for a summary of the material terms of the Incentive Plan. The following table sets forth the number of shares of our common stock subject to outstanding awards under the Incentive Plan, and the number of shares remaining available for future award grants under the Incentive Plan as of December 31, 2012:

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available for Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c)
Equity compensation plans approved by security holders		—		—		—
Equity compensation plans not approved by security holders		—		—		13,808,166
Total		—		—		13,808,166

(1) 2,191,834 shares of restricted stock were issued under the Plan as of December 31, 2012.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Certain Relationships and Related Transactions

Delayed Draw Term Loan Credit Agreement

Certain of our stockholders are lenders under the Loan Agreement. For a description of the terms and conditions of the Loan Agreement, see “Note 6 – Debt – Delayed Draw Term Loan Credit Agreement” to our consolidated financial statements included in this Annual Report on Form 10-K.

Warrant Issuance Agreement

Certain of our stockholders who are lenders under the Loan Agreement received Warrants exercisable for shares of common stock in connection with such loan. For a description of the terms and conditions of the Warrants, see “Note 6 – Debt – Warrant Issuance Agreement” to our consolidated financial statements included in this Annual Report on Form 10-K.

Stockholders Agreement

Pursuant to the Stockholders Agreement, certain of our stockholders have the right to elect members of the Board, as described under “Part III – Item 10. Directors and Executive Officers and Corporate Governance – Corporate Governance.”

Review, Approval or Ratification of Transactions with Related Persons

The Board has recognized that transactions between us and certain related persons present a heightened risk of conflicts of interest. In order to ensure that we act in the best interests of our stockholders, the Board has delegated the review and approval of related party transactions to the Audit Committee in accordance with our written Audit Committee Charter. After its review, the Audit Committee will only approve or ratify transactions that are fair to us and not inconsistent with the best interests of us and our stockholders. Any director who may be interested in a related party transaction shall recuse himself from any consideration of such related party transaction

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In addition, under the Stockholders Agreement, in the two years following the Emergence Date, we may not consummate either (i) a merger, stock issuance, sale of all or substantially all assets, change of entity, or any similar transaction pursuant to which not all holders of our securities entitled to vote for members of the Board are treated equally or (ii) a transaction with an affiliate, without prior approval from either (1) a majority of such securities not held by Whitebox, ZCOF and Waterstone or their affiliates (the “Required Majority”) or (2) the Independent Designee. If such transaction is approved by the Independent Designee without the approval of the Required Majority, we may not consummate any such transaction unless it also receives an opinion from an investment bank or other similar financial advisor that the contemplated transaction is fair, from a financial point of view, to us; provided, however, that such opinion shall only be required (i) for any transaction with a value in excess of $45 million or (ii) for any transaction with an affiliate with a value in excess of $7.5 million. Notwithstanding the foregoing, no such opinion shall be required for any capital contributions used solely to support Par Piceance Energy Equity’s potential $60 million in additional capital contributions to Piceance Energy in accordance with the LLC Agreement, if the timing of such capital contributions makes obtaining such opinion impractical. Certain other identified transactions are also excluded from the above requirements.

Director Independence

Our Board has determined that each of our directors qualifies as an independent director under applicable rules promulgated by the SEC and The NASDAQ Stock Market listing standards (although our common stock is no longer listed on NASDAQ), and has concluded that none of these directors has a material relationship with the Company that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.

Item 14. Principal Accounting Fees and Services.

KPMG LLP (“KPMG”) served as our independent registered public accountants for the year ended December 31, 2011, as well as for the period from January 1, 2012 through the Emergence Date. In connection with our emergence from bankruptcy, and as of the Emergence Date, we engaged EKS&H LLLP (“EKS&H”) as our independent registered public accountants for the four months ending December 31, 2012, to audit our consolidated financial statements for the four months ending December 31, 2012, including the review of our quarterly reporting for the one-month period from September 1, 2012 through September 30, 2012, included in the quarter ending September 30, 2012, and each of the four quarters during the fiscal year ending December 31, 2013.

During those years, KPMG and EKS&H provided services in the following categories and amounts:

	EKS&H		KPMG
	Period from September 1 through December 31, 2012		Period from January 1 through December 31, 2012		Fiscal Year Ended December 31, 2011
Audit fees	$	156,305	$	348,000	$	671,958
Audit-related fees		—		45,444		—
Tax fees		—		1,175,202		255,826
All other fees		—		—		—
Total	$	156,305	$	1,568,646	$	927,784

Audit Fees. Fees for audit services are for the audits of our annual financial statements and reports on internal controls required by the Sarbanes-Oxley Act of 2002 and reviews of our quarterly financial statements.

Audit Related Fees. Fees billed for audit related services are services reasonably related to the performance of the audit or review of the Predecessor’s consolidated financial statements or internal control over financial reporting.

Tax Fees. Fees for tax services are for tax preparation for the Predecessor and its subsidiaries.

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Audit Committee Pre-Approval Policy

Our independent registered public accounting firms may not be engaged to provide non-audit services that are prohibited by law or regulation to be provided by it, nor may either of our independent registered public accounting firms be engaged to provide any other non-audit service unless it is determined that the engagement of the principal accountant provides a business benefit resulting from its inherent knowledge of us while not impairing its independence. Our Audit Committee must pre-approve permissible non-audit services. During fiscal year 2012, our Audit Committee approved 100% of the non-audit services provided to us by our independent registered public accounting firms.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) Financial Statements.

	Page No.
Reports of Independent Registered Public Accounting Firm		F-1
Consolidated Balance Sheets		F-3
Consolidated Statements of Operations		F-4
Consolidated Statements of Changes in Equity		F-5
Consolidated Statements of Cash Flows		F-6
Notes to Consolidated Financial Statements		F-7

(a)(2) Financial Statement Schedules. None.

(a)(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.****
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	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. Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on September 7, 2012.
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.
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.*

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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.***
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.***
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	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.
10.6	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.
10.7	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.
10.8	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.
10.9	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.
10.10	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.
10.11	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.
10.12	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.
10.13	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.
10.14	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.*
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 EKS&H LLLP***
23.2	Consent of KPMG LLP.***
23.3	Consent of Netherland, Sewell & Associates, Inc.***

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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 350.***
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, 2012.***
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, 2012.
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.

62

Glossary of Oil and Gas Terms

The terms defined in this section are used throughout this Form 10-K:

Bbl. One barrel (of oil or natural gas liquids).

Bcf. Billion cubic feet (of natural gas).

Bcfe. Billion cubic feet equivalent.

Completion. Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Developed acreage. The number of acres which are allocated or held by producing wells or wells capable of production.

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.

Dry hole; dry well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Equivalent volumes. Equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.

Exploratory well. 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 Regulation S-X.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

HBP. Held by production.

Liquids. Describes oil, condensate, and natural gas liquids.

MBbls. Thousands of barrels of oil or natural gas liquids.

Mcf. Thousand cubic feet (of natural gas).

Mcfe. Thousand cubic feet equivalent.

MMBbls. Millions of barrels of oil or natural gas liquids.

MMcf. Million cubic feet.

MMcfe. Million cubic feet equivalent.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers.

NGL. Natural gas liquids.

NYMEX. New York Mercantile Exchange.

Present value or PV10% or “SEC PV10%.” When used with respect to oil and gas reserves, present value or PV10% or SEC PV10% means the estimated future gross revenue to be generated from the production of net proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service, accretion, and future income tax expense or to depreciation, depletion, and amortization, discounted using monthly end-of-period discounting at a nominal discount rate of 10% per annum.

Productive wells. Producing wells and wells that are capable of production in sufficient quantities to justify completion, including injection wells, salt water disposal wells, service wells, and wells that are shut-in.

Proved developed reserves. Estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

63

Proved reserves. 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.

Proved undeveloped reserves. Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.

Undeveloped acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains estimated proved reserves.

Working interest. An operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property and a share of production.

64

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 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 is presented on a different cost basis than that for the periods before the reorganization and, therefore, is not comparable.

/s/ EKS&H LLLP                        

EKS&H LLLP

Denver, Colorado

March 27, 2013

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Delta Petroleum Corporation

We have audited the accompanying consolidated balance sheets of Par Petroleum Corporation (formerly Delta Petroleum Corporation) and subsidiaries (the Predecessor) as of December 31, 2011, and the related consolidated statements of operations (Predecessor), changes in equity (Predecessor), and cash flows (Predecessor) for the period from January 1, 2012 through August 31, 2012 and for the year ended December 31, 2011. 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 financial position of Par Petroleum Corporation and subsidiaries as of December 31, 2011(Predecessor), and the results of their operations (Predecessor) and their cash flows (Predecessor) for the period from January 1, 2012 through August 31, 2012 and for the year ended December 31, 2011, 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-2

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	Successor			Predecessor
	December 31, 2012			December 31,2011
ASSETS
Current assets:
Cash and cash equivalents	$	6,185		$	12,862
Restricted cash		23,970			—
Trade accounts receivable, net of allowance for doubtful accounts of $0 and $254, at December 31, 2012 and December 31, 2011, respectively		17,730			5,606
Prepaid and other current assets		1,575			3,399
Prepaid reorganization costs		—			1,301
Inventories		10,466			180
Total current assets		59,926			23,348
Property and equipment:
Oil and gas properties, at cost, successful efforts method of accounting:
Unproved		—			72,081
Proved		4,804			688,521
Land		—			4,000
Other		1,415			71,567
Total property and equipment		6,219			836,169
Less accumulated depreciation and depletion		(373	)		(475,609	)
Net property and equipment		5,846			360,560
Long-term assets:
Investments in unconsolidated affiliates		104,434			3,649
Intangible assets		8,809			—
Goodwill		7,756			—
Assets held for sale		2,800			—
Other long-term assets		11			340
Total long-term assets		123,810			3,989
Total assets	$	189,582		$	387,897
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Debtor in possession financing	$	—		$	45,047
Current maturities of debt		35,000			—
Accounts payable		25,329			2,582
Other accrued liabilities		981			149
Accrued settlement claims		8,667			—
Accrued reorganization and trustee expense		—			851
7% Senior unsecured notes		—			150,000
3  3/4% Senior convertible notes		—			115,000
Accounts payable		—			13,597
Other accrued liabilities					6,939
Total current liabilities		69,977			334,165
Long-term liabilities:
Long – term debt, net of current maturities and unamortized discount		7,391			—
Derivative liabilities		10,945			—
Asset retirement obligations		512			3,507
Total liabilities		88,825			337,672
Commitments and contingencies
Stockholders’ Equity:
Preferred stock, $0.01 par value: authorized 3,000,000 shares, none issued		—			—
Common stock, $0.01 par value; authorized 300,000,000 shares and 200,000,000 shares at December 31, 2012 and December 31, 2011, respectively, issued 150,080,927 shares and 28,841,177 shares at December 31, 2012 and December 31, 2011, respectively		1,501			288
Additional paid-in capital		108,095			1,641,390
Accumulated deficit		(8,839	)		(1,591,453	)
Total stockholders’ equity		100,757			50,225
Total liabilities and stockholders’ equity	$	189,582		$	387,897

See accompanying notes to consolidated financial statements.

F-3

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1, 2012 through August 31, 2012			Year Ended December 31, 2011
Revenue:
Oil and gas sales	$	2,144		$	23,079		$	63,880
Operating expenses:
Lease operating expense		1,684			9,038			13,755
Transportation expense		—			6,963			13,867
Production taxes		4			979			1,535
Exploration expense		—			2			338
Dry hole costs and impairments		—			151,347			420,402
Depreciation, depletion, amortization and accretion		401			16,041			39,088
General and administrative expense		5,076			9,386			28,124
Total operating expenses		7,165			193,756			517,109
Loss from unconsolidated affiliates		(1,325	)		—			—
Operating loss		(6,346	)		(170,677	)		(453,229	)
Other income and (expense):
Interest expense and financing costs, net		(1,056	)		(6,852	)		(32,324	)
Other income (expense)		86			516			(1,947	)
Realized loss on derivative instruments, net		—			—			(3,368	)
Unrealized (loss) gain on derivative instruments, net		(4,280	)		—			2,993
Income (loss) from unconsolidated affiliates		—			(20	)		344
Total other expense		(5,250	)		(6,356	)		(34,302	)
Loss from continuing operations before income taxes, reorganization items and discontinued operations		(11,596	)		(177,033	)		(487,531	)
Income tax benefit		(2,757	)		—			(4,329	)
Loss from continuing operations		(8,839	)		(177,033	)		(483,202	)
Reorganization items
Professional fees and administrative costs		—			22,354			932
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	)		—
Discontinued operations:
Gain from results of operations and sale of discontinued operations, net of tax		—			—			14,094
Net loss		(8,839	)		(45,437	)		(470,040	)
Less net loss attributable to non-controlling interest included in discontinued operations		—			—			(71	)
Net loss attributable to common stockholders	$	(8,839	)	$	(45,437	)	$	(470,111	)
Amounts attributable to common stockholders:
Loss from continuing operations	$	(8,839	)	$	(45,437	)	$	(484,134	)
Gain from discontinued operations, net of tax		—			—			14,023
Net loss	$	(8,839	)	$	(45,437	)	$	(470,111	)
Basic loss attributable to common stockholders per common share:
Loss from continuing operations	$	(0.06	)	$	(1.57	)	$	(16.79	)
Discontinued operations		—			—			0.49
Net loss	$	(0.06	)	$	(1.57	)	$	(16.30	)
Diluted loss attributable to common stockholders per common share:
Loss from continuing operations	$	(0.06	)	$	(1.57	)	$	(16.79	)
Discontinued operations		—			—			0.49
Net loss	$	(0.06	)	$	(1.57	)	$	(16.30	)

See accompanying notes to consolidated financial statements.

F-4

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In thousands)

							Additional												Total			Non-
	Common Stock						paid-in			Treasury Stock						Accumulated			Stockholders’			controlling			Total
	Shares			Amount			capital			Shares			Amount			Deficit			Equity			Interests			Equity
	(in thousands)
Balance, December 31, 2010 (Predecessor)		28,514		$	285		$	1,635,783			3		$	(279	)	$	(1,121,342	)	$	514,447		$	(2,852	)	$	511,595
Net loss		—			—			—			—			—			(470,111	)		(470,111	)		71			(470,040	)
Employee vesting of treasury stock held by Subsidiary		—			—			(135	)		(3	)		279			—			144			(59	)		85
Issuance of non-vested stock		598			6			(6	)					—			—			—			—			—
Forfeitures		(55	)		—			—			—			—			—			—			—			—
Shares repurchased for withholding taxes		(216	)		(3	)		(993	)		—			—			—			(996	)		—			(996	)
Sale of minority interest		—			—			—			—			—			—			—			2,744			2,744
Stock based compensation		—			—			6,741			—			—			—			6,741			96			6,837
Balance, December 31, 2011 (Predecessor)		28,841			288			1,641,390			—			—			(1,591,453	)		50,225			—			50,225
Net loss		—			—			—			—			—			(45,437	)		(45,437	)		—			(45,437	)
Forfeitures		(58	)		—			—			—			—			—			—			—			—
Stock-based compensation		—			—			1,895			—			—			—			1,895			—			1,895
Balance, August 31, 2012 (Predecessor)		28,783			288			1,643,285			—			—			(1,636,890	)		6,683			—			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		147,656			1,477			101,402			—			—			—			102,879			—			102,879
Balance, August 31, 2012 (Successor)		147,656			1,477			108,085			—			—			—			109,562			—			109,562
Stock issued to settle bankruptcy claims		203			2			(2	)		—			—			—			—			—			—
Stock-based compensation		2,222			22			12			—			—			—			34			—			34
Net loss		—			—			—			—			—			(8,839	)		(8,839	)		—			(8,839	)
Balance, December 31, 2012 (Successor)		150,081		$	1,501		$	108,095			—		$	—		$	(8,839	)	$	100,757		$	—		$	100,757

See accompanying notes to consolidated financial statements.

F-5

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Cash flows from operating activities:
Net loss	$	(8,839	)	$	(45,437	)	$	(470,040	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion – oil and gas		401			16,041			39,082
Depreciation, depletion, amortization – discontinued operations		—			—			5,348
Interest capitalized into note balance		465			2,989			74
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 on sale of assets – discontinued operations		—			—			(14,699	)
(Gain) loss on property sales		(82	)		126			85
Dry hole costs and impairments		—			151,347			420,402
Impairments – discontinued operations		—			—			608
Stock-based compensation		34			1,895			8,003
Amortization of deferred financing costs, bond discount, and installments payable discount		591			—			13,805
Accretion of discount in installments payable		—			—			2,126
Increase in allowance for bad debt		—			—			154
Unrealized loss (gain) on derivative contracts		4,280			—			(2,993	)
(Income) loss from unconsolidated affiliates		1,325			20			344
Deferred income tax expense (benefit)		(2,757	)		—			956
Other		—			(699	)		1,940
Net changes in operating assets and liabilities:
Trade accounts receivable		(2,234	)		3,472			1,535
Deposits and prepaid assets		(538	)		(1,378	)		(3,018	)
Inventories		—			—			(68	)
Other current assets		—			—			(285	)
Accounts payable		2,718			(4,187	)		861
Accrued reorganization costs		—			9,116			851
Other accrued liabilities		—			—			(3,722	)
Assets held for sale working capital, net		—			—			(359	)
Net cash provided by (used in) operating activities		(4,636	)		(20,262	)		990
Cash flows from investing activities:
Additions to property and equipment		—			(1,613	)		(56,058	)
Additions to drilling and trucking equipment – assets held for sale		—			—			(1,529	)
Acquisition of Texadian, net of cash acquired		(17,439	)		—			—
Decrease in restricted deposit		—			—			100,000
Proceeds from the sale of oil and gas properties		—			74,209			40,229
Proceeds from sale of drilling assets – assets held for sale		—			—			3,429
Proceeds from sale of other fixed assets		39			26			—
Proceeds from sale of marketable securities		—			—			61
Capitalized drilling costs owed to operator		(415	)		—			—
Proceeds from sale of unconsolidated affiliates		125			—			1,517
Net cash provided by (used in) investing activities		(17,690	)		72,622			87,649
Cash flows from financing activities:
Proceeds from borrowings		35,000			23,000			117,550
Repayments of borrowings		—			(59,535	)		(104,992	)
Fund distribution agent account		—			(21,805	)		—
Proceeds from (funding of) Wapiti and General Recovery Trusts		2,446			(2,000	)		—
Installments paid of property acquisitions		—						(100,000	)
Recoveries from bankruptcy settlements		5,183			—			—
Restricted cash held to secure letter of credits		(19,000	)		—			—
Payment of deferred financing costs		—			—			(1,529	)
Stock repurchased for withholding taxes		—			—			(996	)
Net cash provided by (used in) financing activities		23,629			(60,340	)		(89,967	)
Net increase (decrease) in cash and cash equivalents		1,303			(7,980	)		(1,328	)
Cash at beginning of period		4,882			12,862			14,190
Cash at end of period	$	6,185		$	4,882		$	12,862
Supplemental cash flow information:
Cash paid for interest and financing costs	$	—		$	3,745		$	19,384
Non-cash investing and financing activities:
Interest payable capitalized to principal balance	$	—		$	—		$	5,573
Non-cash additions to oil and gas properties	$	209		$	—		$	—

See accompanying notes to consolidated financial statements.

F-6

PAR PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(1) Reorganization under Chapter 11

On December 16, 2011, Delta Petroleum Corporation (“Delta”) and its subsidiaries Amber Resources Company of Colorado, DPCA, LLC, Delta Exploration Company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc. and Castle Texas Production Limited Partnership 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”). On January 6, 2012, Castle Exploration Company, Inc., a subsidiary of Delta Pipeline, LLC, also filed a voluntary petition under Chapter 11 in the Bankruptcy Court. Delta and its subsidiaries included in the bankruptcy petitions are collectively referred to as the “Debtors.”

On December 27, 2011, the Debtors filed a motion requesting an order to approve matters relating to a proposed sale of Delta’s assets, including bidding procedures, establishment of a sale auction date and establishment of a sale hearing date. On January 11, 2012, the Bankruptcy Court issued an order approving these matters. On March 20, 2012, Delta announced that it was seeking court approval to amend the bidding procedures for its upcoming auction to allow bids relating to potential plans of reorganization as well as asset sales. On March 22, 2012, the Bankruptcy Court approved the revised procedures.

Following the auction, 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 connection with the Plan, Delta entered into a non-binding term sheet describing a transaction by which Laramie and Delta intended to form a new joint venture called Piceance Energy LLC (“Piceance Energy”). On June 4, 2012, Delta entered into a Contribution Agreement (the “Contribution Agreement”) with Piceance Energy and Laramie to effect the transactions contemplated by the term sheet.

On June 4, 2012, the Debtors filed a disclosure statement relating to the Plan. The Plan was confirmed on August 15, 2012 and 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 (referred to after the closing of the transaction as “Successor”). 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.

On the Emergence Date, Delta also amended and restated its certificate of incorporation and bylaws and changed its name to Par Petroleum Company (“Par”). The amended and restated certificate of incorporation contains restrictions that render void certain transfers of the Company 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 the Company believes may have value. Under the amended and restated bylaws, the Company board of directors has five members, each of whom was appointed by its stockholders pursuant to a Stockholders’ Agreement entered into on the Emergence Date.

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 147.7 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.

In addition, Laramie and Piceance Energy entered into a Management Services Agreement pursuant to which Laramie agreed to provide certain services to Piceance Energy for a fee of $650,000 per month.

(2) Fresh Start Accounting and the Effects of the Plan

As required by U.S. generally accepted accounting principles (“U.S. GAAP”), effective as of August 31, 2012, Par adopted fresh start accounting following the guidance of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852 “Reorganizations” (“ASC 852”). Fresh start accounting 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 “Predecessor”) and are not comparable to the consolidated financial statements presented on or after August 31, 2012. Fresh start accounting 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

F-7

start accounting 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 addition, the cancellation of debt income and the allocation of the attribute reduction for tax purposes is an estimate and will not be finalized until the 2012 tax return is filed sometime during 2013. Any change resulting from this estimate could impact deferred taxes.

Under ASC 852, 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 accounting, 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 7 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 accounting reflects the value of the Successor as determined in the confirmed Plan. Under fresh start accounting, our asset values are remeasured and allocated based on their respective fair values in conformity with the acquisition method of accounting for business combinations in FASB ASC Topic 805, “Business Combinations” (“ASC 805”). 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 section 1124(1) of 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 fresh start condensed consolidated balance sheet presents the implementation of the Plan and the adoption of fresh start accounting 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 accounting in accordance with ASC 852.

F-8

	August 31, 2012
	Predecessor			Plan of Reorganization Adjustments			Fresh Start Accounting Adjustments			Successor
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)		—
Net property and equipment		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
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-9

Notes to Plan of Reorganization and Fresh Start Accounting Adjustments

(a) 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.

(b) Reflects extinguishment of secured debt in exchange for common stock of the Successor. On the Emergence Date, we issued 145,736,082 shares of our common stock and warrants to acquire 9,592,125 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 $0.70 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 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.

(d) Reflects settlement of other claims with common stock of Successor and cash. On the Emergence Date, we issued 1,919,733 shares of our common stock to various creditors. We estimated the fair value of our common stock to be $0.70 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 funding of the Recovery Trusts (see Note 9).

(f) Reflects cancellation of Predecessor common stock.

(g) 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.

(h) Reflects elimination of Predecessor accumulated deficit.

(3) 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. Certain of our oil and gas activities may be conducted through partnerships and joint ventures. We will include our proportionate share of assets, liabilities, revenues and expenses from these entities in our consolidated financial statements. 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 Par Piceance Energy, LLC, which owns our investment in Piceance Energy (see Note 4), and Texadian Energy, Inc. (formerly known as SEACOR Energy Inc. (“Texadian”)), which we acquired December 31, 2012 (see Note 5).

Accounting for the Chapter 11 Filing

The Predecessor followed the accounting prescribed by ASC 852. This accounting literature provides guidance for periods subsequent to a Chapter 11 filing regarding the presentation of liabilities that are and are not subject to compromise by the bankruptcy court proceedings, as well as the treatment of interest expense and presentation of costs associated with the proceedings. As a result of the reorganization, the realization of assets and the satisfaction of liabilities were subject to uncertainty. While operating as a debtor-in-possession under Chapter 11, Predecessor’s ability to sell or otherwise dispose of or liquidate assets or settle liabilities, were subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Credit Facility), in amounts other than those reflected in the accompanying consolidated financial statements of the Predecessor. The accompanying Predecessor consolidated financial statements for the year ended December 31, 2011 do not include any direct adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary as a consequence of the reorganization under the Plan.

The Reorganizations Topic of ASC 852, which is applicable to companies in Chapter 11, generally does not change the manner in which financial statements are prepared. However, it does require that the financial statements for periods subsequent to the filing of the Plan distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Amounts that can be directly associated with the reorganization and restructuring of the business must be reported separately as reorganization items in the statements of operations beginning in the quarter ending December 31, 2011. The balance sheet must distinguish pre-petition liabilities subject to compromise from both those pre-petition liabilities that are not subject to compromise and from post-petition liabilities. Liabilities that may be affected by a plan of reorganization must be reported at the amounts expected to

F-10

be allowed, even if they may be settled for lesser amounts. In addition, cash provided by and used for reorganization items must be disclosed separately. The Company has applied the Reorganizations Topic of ASC 852 effective as of the Effective Date, and has segregated those items as outlined above for all reporting periods subsequent to such date.

Cash Equivalents

We consider all highly liquid investments with maturities at date of acquisition of three months or less to be cash equivalents.

Restricted Cash

As of December 31, 2012, restricted cash consists of amounts held at a commercial bank to support our letter of credit facility totaling approximately $19.0 million (see Note 6). In addition, we have restricted cash of approximately $5.0 million designated to settle bankruptcy matters that is not available for operating activities (see Note 9).

Trade Receivables

As of December 31, 2012, Texadian’s customers primarily included major independent refining and marketing companies. Customers are required to pay in advance or are granted credit on a short-term basis when credit risks are considered minimal. We routinely review our trade receivables and make provisions for doubtful accounts based on existing customer and economic conditions; however, those provisions are estimates and actual results could differ from those estimates and those differences may be material. Trade receivables are deemed uncollectible and removed from accounts receivable and the allowance for doubtful accounts when collection efforts have been exhausted. As of December 31, 2012, we had no allowance for doubtful accounts. Additionally, we provide an accrual for oil and natural gas sales using the sales method by estimating oil and natural gas volumes and prices for months in which revenues have not been received using production and pricing information provided by the operator. Most of Texadian’s physical purchases and sales with the same counterparty are settled on a net basis and therefore Texadian’s receivables are recorded net of any corresponding payables.

Inventories

As of December 31, 2012, Texadian’s inventories, which consist of in transit crude oil, are stated at the lower of cost (using the first-in, first-out method) or market. We record impairments, as needed, to adjust the carrying amount of inventories to the lower of cost or market.

Investments in Unconsolidated Affiliates

Investments in operating entities where we have the ability to exert significant influence, but do not control the operating and financial policies, are accounted for using the equity method. Our share of net income of these entities is recorded as income (loss) from unconsolidated affiliates in the consolidated statements of operations.

At December 31, 2012, our investment in unconsolidated affiliates consisted of our ownership interest in Piceance Energy (see Note 4). Until November 2011, the Predecessor owned a 49.8% interest in DHS Drilling Company (“DHS”). The Predecessor’s representatives constituted a majority of the members of the board of directors of DHS and the Predecessor had the right to use all of the rigs owned by DHS on a priority basis and, accordingly, DHS was consolidated in these financial statements until we disposed of DHS in 2011.

Assets Held for Sale

As of December 31, 2012, we have classified our compressors as held for sale, which are recorded at the lower of cost or estimated net realizable value. These compressors are not in use and are not being depreciated.

Property and Equipment

We account for our oil and natural gas 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. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological or geophysical expenses and delay rentals for 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.

F-11

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

Other property and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives ranging from three to 15 years.

Goodwill and Other Intangible Assets

We recorded goodwill as a result of our acquisition of Texadian. Goodwill is attributable to the synergies 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, as a result of our acquisition of Texadian, 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.

Impairment of Goodwill and Long-Lived Assets

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. Qualitative factors assessed for the reporting unit would include the competitive environments and financial performance of the reporting unit. 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, based upon a multiple of estimated earnings. 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. The fair value calculation uses level 3 (see Note 7) inputs and includes multiple assumptions and estimates, including the projected cash flows and discount rates applied. Changes in these assumptions and estimates could result in goodwill impairment that could materially adversely impact our financial position or results of operations.

Long-lived assets are reviewed for impairment quarterly or when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

Estimates of expected future cash flows represent our best estimate based on reasonable and supportable assumptions and projections. For proved properties, if the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized are permanent and may not be restored in the future.

We assess proved properties on an individual field basis for impairment each quarter when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For proved properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs.

For unproved properties, the need for an impairment charge is based on our plans for future development and other activities impacting the life of the property and our ability to recover our investment. When we believe the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. For the period from September 1 through December 31, 2012, there were no impairments recorded by the Successor. 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 to write-down these assets to fair value at that time. The Predecessor’s assets were further adjusted due to the application of fresh start accounting upon the Predecessor’s emergence from Chapter 11. The Predecessor recognized impairment expenses totaling approximately $151.3 million for the period January 1, 2012 through August 31, 2012 and $420.4 million for the year ended December 31, 2011, respectively.

F-12

Asset Retirement Obligations

Our asset retirement obligations arise from the plugging and abandonment liabilities for our oil and gas wells. The following is a reconciliation of our asset retirement obligations (in thousands):

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January  1 through August 31, 2012			Year Ended December 31, 2011
Asset retirement obligation – beginning of period	$	476	$	3,799		$	3,931
Accretion expense		36		178			273
Change in estimate		—		437			(135	)
Obligations incurred (from new wells)		—		—			385
Obligations settled		—		—			(296	)
Obligations on sold properties		—		—			(359	)
Settlement upon transfer to Piceance Energy		—		(3,938	)		—
Asset retirement obligation – end of period		512		476			3,799
Less: Current portion of asset retirement obligation		—		—			(292	)
Long-term asset retirement obligation	$	512	$	476		$	3,507

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

Derivatives and Other Financial instruments

We may periodically enter into commodity price risk transactions to manage our exposure to ethanol, oil and gas 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.

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, we issued warrants (see Note 6) that are not considered to be indexed to our equity. Accordingly, these warrants are accounted for as liabilities. In addition, the Loan Agreement contains certain puts that are 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.

The carrying value of trade accounts receivable and accounts payable approximates fair value due to their short term nature. Our long-term debt is recorded on the amortized cost basis. We estimate its fair value to be approximately $10.9 million at December 31, 2012 using a discounted cash flow analysis and an estimate of the current yield (15.4%) by reference to market interest rates for term debt of comparable companies which is considered a level 3 fair value measurement (see Note 7). Our derivatives are recorded at fair value.

Accrued Settlement Claims

As of December 31, 2012, we have accrued approximately $8.7 million relating to claims resulting from our bankruptcy (See Note 9).

F-13

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 based on a “more likely than not” standard, and to the extent this threshold is not met, a valuation allowance is recorded.

We recognize in the financial statements 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 2009, 2010, and 2011. 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.

Stock Based Compensation

We recognize the cost of share based payments over the period the employee provides service, generally the vesting period, and includes such costs in general and administrative expense in the 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

Oil and Gas

Revenues are recognized when title to the products transfers to the purchaser. We follow the “sales method” of accounting for our natural gas and crude oil revenue, so that we recognize sales revenue on all natural gas or crude oil sold to its 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, 2012, our aggregate natural gas and crude oil imbalances were not material to our consolidated financial statements.

Marketing and Transportation

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.

Texadian will earn revenues from the sale of crude oil, blendstocks and refined products, the rental of rail cars, and through voyage affreightment contracts on leased-in liquid tank barges and towboats. Revenues and related costs from crude oil, blendstocks and refined products are recorded when title transfers to the buyer. Revenues from the rental of railcars are recognized ratably over the lease periods. Revenues from voyage affreightment contracts are generally recognized over the progress of the voyage while the related costs are expensed as incurred. Unearned revenues arise and are recorded as a liability when customers pay in advance for products or services.

Major Customers

For the year ended December 31, 2012 and 2011, two and three customers accounted for approximately 54% and 59%, respectively, of Texadian’s operating revenues (see Note 5). The loss of any of these customers could have a material adverse effect on our future results of operations.

For the period September 1, 2012 to December 31, 2012, we had one customer that accounted for 96% of the Sucessor’s total oil and natural gas sales. During the period from January 1, 2012 to August 31, 2012 we had two customer that accounted individually for 59% and 24%, respectively, of the Predecessor’s total oil and natural gas sales. For the year ended December 31, 2011, two customers accounted individually for 56% and 19%, respectively, of the Predecessor’s total oil and gas sales. Although a substantial portion of production is purchased by these major customers, we do not believe that the loss of a customer would have a material adverse effect on our business as other customers or markets would be accessible to us.

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 foreign currency losses, net in the accompanying consolidated statements of operations in the period in which the currency exchange rates change.

F-14

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 under fresh start accounting, fair value of assets and liabilities recorded under purchase accounting, oil and natural gas reserves, bad debts, depletion and impairment of oil and natural gas properties, income taxes and the valuation allowances related to deferred tax assets, derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.

Recently Adopted Guidance

Comprehensive Income—In June 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-05, related to ASC Topic 220, Comprehensive Income: Presentation of Comprehensive Income and in December 2011 the FASB issued ASU 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU 2011-05. These standards eliminate the current option to report other comprehensive income and its components in the statement of changes in equity. The adoption of this amendment in 2012 did not have a material effect on the presentation of our consolidated financial statements.

Fair Value Measurement—In May 2011, the FASB issued new guidance related to ASC Topic 820, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The new guidance results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and International Financial Reporting Standards (“IFRS”), changes some fair value measurement principles and requires additional disclosure. The ASU was effective for interim and annual periods beginning on or after December 15, 2011. The adoption of this amendment in 2012 did not have a material effect on the presentation of our consolidated financial statements.

(4) Investments 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, and as a result, we do not meet the accounting criteria which require us to consolidate the joint venture. The LLC agreement that governs Piceance Energy 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, if approved by a majority of its board. If any member does not fund their share of the capital call, their 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 oil and gas properties and related assets with a borrowing base currently set at $140 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.

Piceance Energy holds various commodity hedging instruments to mitigate a portion of the effect of oil and natural gas price fluctuations. The contracts are in the form of costless collars of 10,000 MMBtu/day with floors of an average of $3.18 and ceilings of $4.22 as well as swaps of 10,000 MMBtu/day for an average price of $3.46 all through September 2014. Piceance Energy also holds gas gathering and processing contracts for a fixed rate expiring on various dates beginning in 2017 through 2032. Some of the contracts require a minimum throughput commitment.

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

	Period from September 1 through December 31, 2012
	(in thousands)
Beginning balance	$	105,344
Loss from unconsolidated affiliates		(1,325	)
Capitalized drilling costs obligation paid		415
Ending balance	$	104,434

Summarized balance sheet information and our share of the equity investment are as follows:

	December 31, 2012
	100%			Our Share
	(in thousands)
Assets
Cash and equivalents	$	234		$	78
Accounts receivable		4,836			1,612
Prepaids and other assets		1,205			402
Total current assets		6,275			2,092
Oil and gas property, successful efforts method		533,279			177,795
Other real estate and land		14,322			4,775
Office furniture and equipment		2,086			695
Total		549,687			183,265
Less: accumulated depletion, depreciation and amortization		(89,673	)		(29,897	)
Total property and equipment, net		460,014			153,368
Deferred issue costs and other assets, net		977			325
Total assets	$	467,266		$	155,785

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	December 31, 2012
	100%			Our Share
	(in thousands)
Liabilities and Members’ Equity
Accounts payable and accrued liabilities	$	10,169		$	3,390
Oil and gas sales payable		1,657			552
Total current liabilities		11,826			3,942
Note payable		90,000			30,006
Derivative liabilities		1,525			508
Asset retirement obligation		2,844			948
Total non-current liabilities		94,369			31,462
Total liabilities		106,195			35,404
Members equity
Members’ equity		365,046			121,706
Accumulated deficit		(3,975	)		(1,325	)
Total members equity		361,071			120,381
Total liabilities and members’ equity	$	467,266		$	155,785

At December 31, 2012, our equity in the underlying net assets of Piceance Energy exceeded the carrying value of our investment by approximately $15.9 million. We attribute this difference, which is expected to be permanent, to lack of control and marketability discounts.

Summarized income statement information and our share for the period for which our investment was accounted for under the equity method is as follows:

	September 1 through December 31, 2012
	100%			Our Share
	(in thousands)
Oil, natural gas and natural gas liquids revenues	$	19,391		$	6,465
Oil and gas operating expenses		9,100			3,034
Depletion, depreciation and amortization		8,523			2,842
Management fee		3,250			1,084
General and administrative		613			204
Total operating expenses		21,486			7,164
Loss from operations		(2,095	)		(699	)
Other income (expense)
Loss from derivatives		(918	)		(306	)
Interest expense and debt issue costs		(976	)		(325	)
Other income		14			5
Total other expense		(1,880	)		(626	)
Net loss	$	(3,975	)	$	(1,325	)

(5) Acquisition

On December 31, 2012, we acquired Texadian Energy, Inc. (formerly known as SEACOR Energy, Inc. (“Texadian”), an indirect wholly-owned subsidiary of SEACOR Holdings Inc., for $14.0 million plus estimated net working capital of approximately $4.0 million at closing resulting in approximately $18.0 million of cash paid at closing. Texadian operates a crude oil marketing, transportation, distribution and marketing business with significant logistics capabilities. We acquired Texadian in furtherance of our growth strategy that focuses on the acquisition of income producing businesses. The purchase price for the acquisition was funded with a combination of cash and additional borrowings under an amendment to our existing delayed draw term loan facility referred to as the Tranche B Loan (see Note 6).

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The purchase was accounted for as a purchase business combination in accordance with ASC 805 whereby the purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values on the date of acquisition (see Note 7). Goodwill is defined in ASC 805 as the future economic benefit of other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is attributable to the synergies 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		7,756
Net non cash working capital		3,631
Deferred tax liabilities		(2,757	)
Total, net of cash acquired	$	17,439

The intangible assets will be amortized over their estimated useful lives on a straight line basis. The weighted average useful life is 7.3 years. Estimated amortization expense is expected to be as follows (in thousands):

Year Ended
2013	$	2,008
2014		2,008
2015		908
2016		908
2017		908
Thereafter		2,069
	$	8,809

None of the goodwill or intangible assets are expected to be deductible for income tax reporting purposes.

The results of operations of Texadian will be included in our consolidated statement of operations beginning January 1, 2013. Texadian’s revenues for the year ended December 31, 2012 were approximately $515.5 million (unaudited), and its net income was approximately $2.3 million (unaudited), of which approximately $122.9 (unaudited) million revenue and net income of approximately $800,000 (unaudited) is attributable to the period from September 1, 2012 through December 31, 2012. Texadian’s revenues for the year ended December 31, 2011 was approximately $731 million (unaudited), and its net loss was approximately $(748,000) (unaudited). Accordingly, had the acquisition occurred as of September 1, 2012, our consolidated revenue and net loss would have been approximately $125.0 million (unaudited) and $8.6 million (unaudited), respectively, including amortization of the acquired intangibles. We have not presented pro forma results for Predecessor periods as the entities are not comparable. Acquisition costs totaled approximately $556,000 are included in general and administrative expenses in our consolidated statement of operations.

(6) Debt

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 $30.0 million. We borrowed $13.0 million on the Effective Date in order to, along with the proceeds from the Contribution Agreement, (i) repay the loans and obligations due under the DIP Credit Facility, and (ii) pay allowed but unpaid administrative expenses to the Debtors related to the Plan.

Below are certain of the material terms of the Loan Agreement:

Interest. At our election, any Loans will bear interest at a rate equal to 9.75% per annum payable either (i) in cash, quarterly, in arrears at the end of each calendar quarter or (ii) in-kind, accruing quarterly. In addition, all repayments due under the Loan Agreement will be charged a minimum of a 3% repayment premium. Accordingly, we will accrete amounts due for the minimum repayment premium over the term of loan using the effective interest method.

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At any time after an event of default under the Loan Agreement has occurred and is continuing, (i) all outstanding obligations will, to the extent permitted by applicable law, bear interest at a rate per annum equal to 11.75% and (ii) all interest accrued and accruing will be payable in cash on demand.

Prepayment. We may prepay Loans at any time, in any amount. Such prepayment is to include all accrued and unpaid interest on the portion of the obligations being prepaid through the prepayment date. If at any time within the twelve months following the Emergence Date, we prepay the obligations due, in whole, but not in part, then in addition to the repayment of 100% of the principal amount of the obligations being prepaid plus accrued and unpaid interest thereon, we are required to pay the interest that would have accrued on the prepaid amount through the first anniversary of the Emergence Date plus a 6% prepayment premium.

In addition to the above described prepayment premium, we will pay a repayment premium equal to the percentage of the principal repaid during the following periods:

Period	Repayment Premium
From the Emergence Date through the first anniversary of the Emergence Date		6	%
From the day after the first anniversary of the Emergence Date through the second anniversary of the Emergence Date		5	%
At all times from and after the day after the second anniversary of the Emergence Date		3	%

We are also required to make certain mandatory repayments after certain dispositions of property, debt issuances, joint venture distributions from Piceance Energy, casualty events and equity issuances, in each case subject to customary reinvestment provisions. These mandatory repayments are subject to the prepayment premiums described above.

The contingent repayments described above are required to be accounted for as an embedded derivative. The estimated fair of the embedded derivative at issuance was approximately $65,000 and was recorded as a derivative liability with the offset to debt discount. Subsequent changes in fair value are reflected in earnings.

Collateral. The Loans and all obligations arising under the Loan Agreement are secured by (i) a perfected, first-priority security interest in all of our assets other than our equity interest in Piceance Energy held by Par Piceance Energy Equity, pursuant to a pledge and security agreement made by us and certain of our subsidiaries in favor of the Agent, and (ii) a perfected, second-lien security interest in our equity interest in Piceance Energy held by Par Piceance Energy Equity, pursuant to a pledge agreement by Par Piceance Energy Equity in favor of the Agent. The priority of the Lenders’ security interest in our assets is specified in that certain intercreditor agreement (the “Intercreditor Agreement”), among JPMorgan Chase Bank, N.A., as administrative agent for the First Priority Secured Parties (as defined in the Intercreditor Agreement), the Agent, as administrative agent for the Second Priority Secured Parties (as defined in the Intercreditor Agreement), the Company and Par Piceance Energy Equity.

Guaranty. All of our obligations under the Loan Agreement are unconditionally guaranteed by the Guarantors.

Fees and Commissions. We agreed to pay the Agent an annual nonrefundable administrative fee that was earned in full on the Effective Date. In addition, we agreed to pay the Lenders a nonrefundable closing fee that was earned in full on the Effective Date.

Warrants. As consideration for granting the Loans, we have also issued warrants to the Lenders to purchase shares of our common stock as described under “– Warrant Issuance Agreement” below.

Term. All loans and all other obligations outstanding under the Loan Agreement are payable in full on August 31, 2016.

Covenants. The Loan Agreement has no financial covenants that we are required to comply with; however, it does require us to comply with various affirmative and negative covenants affecting our business and operations which we were in compliance with at December 31, 2012.

Amendment to the Loan Agreement—Tranche B Loan

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 the Lenders agreed to extend additional borrowings to us (the “Tranche B Loan”). The total commitment of the Tranche B Loan of $35.0 million was drawn at closing. In addition to funding a portion of the purchase price of the acquisition of Texadian, the Tranche B Loan provides cash collateral for the Letter of Credit Facility with Compass Bank (as described below).

Set forth below are certain of the material terms of the Tranche B Loan:

Interest. At our election, the Tranche B Loan will bear interest at a rate equal to 9.75% per annum payable either (i) in cash or (ii) in-kind.

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At any time after an event of default has occurred and is continuing, (i) all outstanding obligations will, to the extent permitted by applicable law, bear interest at a rate per annum equal to 11.75% and (ii) all interest accrued and accruing will be payable in cash on demand.

Prepayment. We may prepay the Tranche B Loan 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 entire outstanding principal amount of the Tranche B Loan.

Maturity date. The maturity date is July 1, 2013.

Collateral. The Tranche B Loan is secured by a lien on substantially all of our assets and our subsidiaries, including Texadian, but excluding our equity interests in Piceance Energy.

Guaranty. All of our obligations under the Tranche B Loan are unconditionally guaranteed by the Guarantors, including, Texadian.

Fees and Commissions. We agreed to pay the Lenders a nonrefundable exit fee equal to five percent (5%) of the aggregate amount of the Tranche B Loan. The exit fee is earned in full and payable on the maturity date of the Tranche B Loan or, if earlier, the date on which the Tranche B Loan is paid in full. Accordingly, we will accrete amounts due for the nonrefundable exit fee over the term of loan using the effective interest method.

Letter of Credit Facility

On December 27, 2012, we entered into a letter of credit facility agreement with Compass Bank, as the lender (the “Compass Letter of Credit Facility”). The Compass Letter of Credit Facility, which matures on December 26, 2013, provides for a letter of credit facility in an aggregate principal amount of $30.0 million that is available for the issuance of cash-collateralized standby letters of credit for us or any of our subsidiaries’ account. Letters of credit issued under the Compass Letter of Credit Facility are secured by an amount of cash pledged and delivered by us to Compass equal to one hundred five percent (105%) of the undrawn amount of all outstanding letters of credit. We agreed to pay a letter of credit fee equal to one and one half percent (1.5%) per annum of the stated face amount of each letter of credit for the number of days such letter of credit is to remain outstanding plus standard and customary administrative fees. The Compass Letter of Credit Facility does not contain any financial covenants; however, it does require us to comply with various affirmative and negative covenants affecting our business and operations, which we are in compliance with at December 31, 2012.

In connection with the acquisition of Texadian, Compass Bank issued an Irrevocable Standby Letter of Credit in favor of SEACOR Holdings in the amount of $11.71 million (the “Irrevocable Standby Letter of Credit”). The Irrevocable Standby Letter of Credit will secure SEACOR Holdings in the event that either of the following letters of credit is drawn: (i) the letter of credit issued by DNB Bank, ASA in favor of Suncor Energy Marketing Inc., with an original maturity date of February 5, 2013; or (ii) the letter of credit issued by DNB Bank, ASA in favor of Cenovus Energy Marketing Services Limited, with an original maturity date of February 5, 2013. These letters of credit have been terminated and released.

Cross Default Provisions

Included within each of the Company’s 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.

Warrant Issuance Agreement

Pursuant to the Plan, on the Effective Date, we issued to the Lenders warrants (the “Warrants”) to purchase up to an aggregate of 9,592,125 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 Effective 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 $0.01 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 Warrant Shares issued on the Effective Date was determined based on the number of shares of our common stock issued as allowed claims on or about the Effective Date by the Bankruptcy Court pursuant to the Plan. The Warrant Issuance Agreement provides that the number of Warrant Shares and the Exercise Price shall be adjusted in the event that any additional shares of common stock or securities convertible into common stock (the “Unresolved Bankruptcy Shares”) are authorized to be issued under the Plan by the Bankruptcy Court after the Effective Date as a result of any unresolved bankruptcy claims under the Plan. Upon each issuance of any Unresolved Bankruptcy Shares, the Exercise Price shall be reduced to an amount equal to the product obtained by multiplying (A) the Exercise Price in effect immediately prior to such issuance or sale, by (B) a fraction, the numerator of which shall be (x) 147,655,815 and (y) the denominator of which shall be the sum of (1) 147,655,815 and (2) and the number of additional Unresolved Bankruptcy Shares authorized for issuance under the Plan. Upon each such adjustment of the Exercise Price, the number of Warrant Shares shall be increased to the number of shares determined by multiplying (A) the number of Warrant Shares which could be obtained upon exercise of such Warrant immediately prior to such adjustment by (B) a fraction, the numerator of which shall

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be the Exercise Price in effect immediately prior to such adjustment and the denominator of which shall be the Exercise Price in effect immediately after such adjustment. In the event that any Lender or its affiliates fails to fund its pro rata portion of any Loans required to be made under the Loan Agreement, then the number of Warrant Shares exercisable under the Warrants held by such Lender will be reduced to an amount equal to the product of (i) the number of Warrant Shares initially exercisable under the Warrant held by the Lender and (ii) a fraction equal to one minus the quotient obtained by dividing (x) the amount of Loans previously made under the Loan Agreement by such Lender by (y) such Lender’s full commitment for Loans.

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.

Based on certain anti-dilution provisions in the Warrant Issuance Agreement, we have concluded that the Warrants are not indexed to our equity. Accordingly, we have 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 will be amortized over the life of the Loan Agreement, using the effective interest method. Subsequent changes in the fair value of the Warrants will be reflected in earnings.

Summary

Our debt at December 31, 2012 is as follows (in thousands):

Tranche B Loan	$	35,000
Delayed Draw Term Loan Agreement		13,465
Less: unamortized debt discount – warrants		(6,014	)
Less: unamortized debt discount – embedded derivative		(60	)
Total debt, net of unamortized debt discount		42,391
Less: current maturities		(35,000	)
Long term debt, net of current maturities and unamortized discount	$	7,391

For the period from September 1 through December 31, 2012, interest expense totaled approximately $1,056,000 consisting of approximately $432,000 of interest accrued in kind and approximately $33,000 of accretion related to the 3% repayment premium both of which are related to the Loan Agreement and approximately $592,000 related to amortization of the debt discount originating from the warrants and embedded derivative. We have made no cash interest payments during the period from September 1, 2012 to December 31, 2012.

Debtor in Possession Credit Agreement

On December 21, 2011, Predecessor entered into a senior secured debtor-in-possession credit facility (the “DIP Credit Facility”) in connection with the bankruptcy filing. Up to $57.5 million could be borrowed under the DIP Credit Facility, of which approximately $45 million was initially drawn by Predecessor to repay all amounts outstanding under the previous credit agreement, which was then terminated. The DIP Credit Facility was amended in March 2012 to increase the maximum borrowing capacity by $1.4 million to $58.9 million. All of the loans under the DIP Credit Facility were term loans. The interest rate under the DIP Credit Facility was 13% plus 6% per annum in payment-in-kind interest. The initial maturity date of the DIP Credit Facility was June 30, 2012. Predecessor subsequently entered into a series of forbearance agreements extending the maturity date to August 31, 2012. The DIP Credit Facility was repaid in full and terminated in accordance with the Plan.

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7% Senior Unsecured Notes, due 2015

On March 15, 2005, Predecessor issued 7% senior unsecured notes due 2015 for an aggregate principal amount of $150.0 million. The bankruptcy filing constituted an event of default on the notes resulting in all principal, interest and other amounts due relating to the notes becoming immediately due and payable. The notes were settled in accordance with the Plan.

3 ³/₄% Senior Convertible Notes, due 2037

On April 25, 2007, Predecessor issued $115.0 million aggregate principal amount of 3 ³/₄% Senior Convertible Notes due 2037 for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The bankruptcy filing constituted an event of default on the notes resulting in all principal, interest and other amounts due relating to the notes becoming immediately due and payable. The notes were settled in accordance with the Plan.

(7) Fair Value Measurements

We follow accounting guidance which defines fair value, establishes a framework for measuring fair value in U.S. GAAP, and requires additional disclosures about fair value measurements. As required, we applied the following fair value hierarchy:

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 transfer 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. These valuation policies are determined by our Chief Financial Officer and approved by our Chief Executive Officer. They are discussed with our Audit Committee as deemed appropriate. Each quarter, our Chief Financial Officer and Chief Executive Officer update the inputs used in the fair value measurement and internally review the changes from period to period for reasonableness. 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 Accounting – The fair value of the Successor was based on its estimated enterprise value post-bankruptcy using valuation techniques described in notes (a) through (f) described 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 have been reflected in the Successor’s consolidated balance sheet as of August 31, 2012.

	Fair Value at August 31, 2012		Fair Value Technique
	(in thousands)
Oil and gas properties
Proved	$	4,587		(a	)(b)
Other assets
Frac tanks	$	1,400		(c	)
Compressors		2,800		(d	)
Miscellaneous		39		(e	)
	$	4,239
Investment in Piceance Energy	$	105,344		(f	)

(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.

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(c) The estimated fair value of our frac tanks was valued using a market valuation technique which was based on published listings of similar equipment. We consider this to be a level 2 fair value measurement.

(d) The estimated fair value of the compressor units was valued using a market valuation technique based on standalone bids received by third-parties. We consider this to be a level 2 fair value measurement.

(e) 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.

(f) The estimated fair value of our investment in Piceance Energy is 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. A change in significant inputs such a reduction in commodity pricing or an increase in discount rates would result in a lower fair value.

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 (e) described below.

	Fair Value at December 31, 2012			Fair Value 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 shippers, 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.

Proved property impairments – The fair values of the proved properties are estimated using internal discounted cash flow calculations based upon our estimates of reserves and are considered to be level 3 fair value measurements. This estimation is based on an independent reserve report with industry standard discounts applied to the reserves.

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Asset retirement obligations – The initial fair values of the asset retirement obligations are estimated using the income valuation technique and internal discounted cash flow calculations based upon the our asset retirement obligations, including revisions of the estimated fair values during the period from September 1 through December 31, 2012, and are considered to be level 3 fair value measurements.

Assets and Liabilities Measure at Fair Value on a Recurring Basis

Derivative liabilities associated with our debt agreement – Derivative liabilities include the Warrants and fair value is estimated using an income valuation technique and 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 the initial stock price of $0.70 per share, initial exercise price $0.01, term of 10 years, risk free rate of 1.7%, and expected volatility of 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 $0.69 per share at issuance or $6.6 million. 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. There was no material change in the inputs used to measure fair value or in the fair value as of December 31, 2012.

In addition, our Loan Agreement contains 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 consider 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 of approximately $65,000 at issuance 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. There was no material change in the inputs used to measure fair value or in the fair value as of December 31, 2012.

Derivative instruments – With the acquisition of Texadian, we assumed certain open positions consisting of non-exchange traded fixed price physical contracts and exchange traded commodity swap, options and futures contracts. 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 and from third party broker quotes and pricing providers.

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 consist of the following (in thousands):

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

	Location on Consolidated Balance Sheet		Fair Value at December 31, 2012
			(in thousands)
Commodities – physical forward contracts		Prepaid and other current assets	$	(307	)
Commodities – exchange traded futures		Prepaid and other current assets	$	542
Warrant derivatives		Noncurrent liabilities	$	(10,900	)
Embedded derivative		Noncurrent liabilities	$	(45	)

F-23

A rollforward of Level 3 derivative warrants and the embedded derivative measured at fair value using level 3 on a recurring basis is as follows (in thousands):

Description
Balance, at September 1, 2012	$	(6,665	)
Purchases, issuances, and settlements		—
Total unrealized losses included in earnings		(4,280	)
Transfers		—
Balance, at December 31, 2012	$	(10,945	)

The estimated fair value and notional amounts of our open physical forward commodity contracts are shown in the table below (in thousands except volumes):

	Open Physical Forward Contracts
	December 31, 2012
				Notional Amounts
	Fair Value			Value		Volumes		Volume Unit		Maturity Dates
Crude oil	$	(227	)	WTI plus $	3.00		60,000		barrels		January 2013
Crude oil	$	(80	)	WTI plus $	15.00		21,497		barrels		January 2013

F-24

(8) Discontinued Operations

During the second quarter of 2011, Predecessor sold the remaining portion of our interests in non-core assets primarily located in Texas and Wyoming to Wapiti Oil and Gas, LLC (“Wapiti Oil and Gas”) (the “Wapiti Transaction”) for gross cash proceeds of approximately $43.2 million. On October 31, 2011, Predecessor sold its stock, representing a 49.8% ownership interest in DHS, to DHS’s lender for $500,000. In accordance with U.S. GAAP, the results of operations relating to these properties and DHS have been reflected as discontinued operations for all periods presented.

We had no activity from discontinued operations for the periods from September 1 through December 31, 2012 or from January 1 through August 31, 2012. The following table shows the oil and gas segment and drilling segment revenues and expenses included in discontinued operations as described above ended December 31, 2011 (in thousands):

	Predecessor Year Ended December 31, 2011
	Oil and Gas			Drilling			Total
Revenues:
Oil and gas sales	$	10,276		$	—		$	10,276
Contract drilling and trucking fees		—			45,241			45,241
Total Revenues		10,276			45,241			55,517
Operating Expenses:
Lease operating expense		2,482			—			2,482
Transportation expense		16			—			16
Production taxes		370			—			370
Dry hole costs and impairments(1)		608			—			608
Depreciation, depletion, amortization and accretion – oil and gas		2,796			—			2,796
Drilling and trucking operating expenses		—			35,617			35,617
Depreciation and amortization – drilling and trucking(2)		—			2,669			2,669
General and administrative expense		—			3,014			3,014
Total operating expenses		6,272			41,300			47,572
Operating income		4,004			3,941			7,945
Other income and (expense):
Interest expense and financing costs, net		—			(6,911	)		(6,911	)
Other income		—			2,734			2,734
Total other expense		—			(4,177	)		(4,177	)
Income (loss) from discontinued operations		4,004			(236	)		3,768
Income tax expense(3)		(1,724	)		—			(1,724	)
Income (loss) from results of operations of discontinued operations, net of tax		2,280			(236	)		2,044
Gain on sales of discontinued operations, net of tax(4)		6,874			5,176			12,050
Income from results of operations and sale of discontinued operations, net of tax	$	9,154		$	4,940		$	14,094

⁽¹⁾ Dry Hole Costs and Impairments. In 2011, we recorded impairments on our Columbia River, Greentown and Gulf Coast properties of $491,000 prior to their sale. In accordance with accounting standards, the impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction with the Wapiti Transaction were reflected as discontinued operations.

⁽²⁾ Depreciation and Amortization – Drilling and Trucking. Depreciation and amortization– drilling and trucking was $2.7 million for the year ended December 31, 2011. We stopped recording depreciation expense beginning in March 2011 in accordance with accounting rules related to the asset held for sale treatment of DHS.

⁽³⁾ Income tax expense. For the year ended December 31, 2011, we recorded a tax benefit of approximately $1.2 million due to a non-cash income tax benefit related to gains from discontinued oil and gas operations. U.S. GAAP requires all items be considered, including items recorded in discontinued operations, in determining the amount of tax benefit that results from a loss from continuing operations that should be allocated to continuing operations. In accordance with U.S. GAAP, we recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations.

F-25

⁽⁴⁾ Gain on sales of discontinued operations – oil and gas. In accordance with U.S. GAAP, we recognized a $5.6 million gain on sale ($8.9 million gain, net of $3.3 million of tax) for the year ended December 31, 2011 that is reflected in discontinued operations. In June 2011, DHS sold certain of its trucking assets for $3.3 million in proceeds and a gain of $2.9 million.

(9) Commitments and Contingencies

Recovery Trusts

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, 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 $1.0 million each pursuant to the Plan.

On September 19, 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. Further distributions are not anticipated from the Wapiti Trust and the Wapiti Trust is anticipated to be 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 Executive Officer is the 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 for each of the Recovery Trusts, subject to the terms of the respective trust agreements 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 March 19, 2013, the Recovery Trusts have released approximately $5.2 million to us, which is available for our general use, resulting from the distribution agent resulting from excess proceeds after a negotiated reduction in certain fees and claims associated with the bankruptcy, as well as a favorable variance in actual expenses incurred compared to 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, 106 claims totaling approximately $73.7 million had been filed in the bankruptcy. Between the Emergence Date and December 31, 2012, the Recovery Trustee settled 25 claims with an aggregate face amount of approximately $6.6 million for $258,905 in cash and 202,753 shares of stock. Subsequent to year end and up to March 19, 2013, the Recovery Trustee settled an additional 25 claims with an aggregate face amount of approximately $12.3 million for $676,092 in cash and 1,469,575 shares of stock.

As of March 19, 2013, it is estimated that a total of 56 claims totaling approximately $54.8 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. Par believes 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. In addition, litigation and/or settlement efforts are ongoing with Macquarie Capital (USA) Inc., Swann and Buzzard Creek Royalty Trust, as well as other claim holders.

F-26

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 544 shares per $1,000 of claim. At December 31, 2012, we have reserved approximately $8.7 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at year end. A summary of claims is as follows:

	Emergence-Date August 31, 2012				Year-ended December 31, 2012
	Filed Claims				Settled Claims								Remaining Filed Claims
									Consideration
	Count		Amount		Count		Amount		Cash		Stock		Count		Amount
U.S. Government Claims		3	$	22,364,000		—	$	—	$	—		—		3	$	22,364,000
Former Employee Claims		32		16,379,849		13		3,685,253		229,478		202,231		19		12,694,596
Macquarie Capital (USA) Inc.		1		8,671,865		—		—		—		—		1		8,671,865
Swann and Buzzard Creek Royalty Trust		1		3,200,000		—		—		—		—		1		3,200,000
Other Various Claims*		69		23,120,396		12		2,914,859		29,427		522		57		20,205,537
Total		106	$	73,736,110		25	$	6,600,112	$	258,905		202,753		81	$	67,135,998

	Subsequent to Year-ended December 31, 2012 through March 19, 2013
	Settled Claims								Remaining Filed Claims
					Consideration
	Count		Amount		Cash		Stock		Count		Amount
U.S. Government Claims		—	$	—	$	—		—		3	$	22,364,000
Former Employee Claims		12		11,750,904		278,338		1,361,452		7		943,692
Macquarie Capital (USA) Inc.		—		—		—		—		1		8,671,865
Swann and Buzzard Creek Royalty Trust		—		—		—		—		1		3,200,000
Other Various Claims*		13		581,607		397,754		108,123		44		19,623,930
Total		25	$	12,332,511	$	676,092		1,469,575		56	$	54,803,487

* Includes reserve for contingent/unliquidated claims in the amount of $10 million

Texadian Leases

As of December 31, 2012, Texadian had 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.

Texadian’s railcar leases contain an empty mileage indemnification provision whereby if the empty mileage exceeds the loaded mileage, Texadian is charged for the empty mileage at the rate established by the tariff of the railroad on which the empty miles accrued.

Future minimum payments under operating leases that have a remaining term in excess of one year as of December 31, 2012 were as follows (in thousands):

2013	$	1,496
2014		1,496
2015		1,496
2016		1,496
2017		660
	$	6,644

Employee Matters

The Predecessor had, as of December 31, 2011, agreements with its three executive officers which provide for severance payments equal to three times the average of the officer’s combined annual salary and bonus, benefits continuation and accelerated vesting of options and stock grants in the event that there is a change in control of the Company. These agreements were amended on December 29, 2010 to bring them into compliance with Section 409A of the Code. These executory agreements were neither assumed nor rejected in Delta’s chapter 11 case, though two of them became nonexecutory upon the termination of the executives in question.

(10) Stockholders’ Equity

Pursuant to the Plan, on the Effective 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 145,736,082 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 1,919,733 shares of our common stock, and (iii) the Lenders under the Loan Agreement received warrants to purchase up to an aggregate of 9,592,125 shares of our common stock (which number of shares may be increased to an aggregate of 12,200,000 shares of our common stock pursuant to the terms of the Warrant Issuance Agreement).

F-27

Amendments to the Certificate of Incorporation and Bylaws

Pursuant to the Plan, on the Effective 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.

Registration Rights Agreement

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 sixty (60) days after the Effective Date, any Stockholder or group of Stockholders that, together with its or their affiliates, holds more than fifteen percent (15%) 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 ninety (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 ninety (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.

Preferred Stock

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

Common Stock

On July 12, 2011, the stockholders of Predecessor approved a one-for-ten reverse split of its common stock which became effective on July 13, 2011. All references in the Predecessor financial statements to the number of shares of common stock or options, 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.

On December 31, 2012, a total of 30,524 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 $33,000 relating to these shares, which represents 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 $1.00 to $1.20 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.

F-28

Incentive Plan

On December 20, 2012, our Board of Directors 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 16 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.

On December 31, 2012, a total of 2,191,834 shares of our restricted common stock were granted to members of our Board of Directors and certain key employees. Restricted stock granted to members of our Board of Directors vests in full after one year from the date of grant, while restricted stock granted to employees vests on a pro-rata basis over five years. For the period from September 1, 2012 through December 31, 2012, the following activity occurred under our Incentive Plan:

	Shares		Weighted-Average Grant Date Fair Value
Stock Awards
Non vested balance, beginning of period		—	$	—
Granted		2,191,834		1.09
Vested		—		—
Forfeited		—		—
Non vested balance, end of period		2,191,834	$	1.09

As of December 31, 2012, there are approximately $2.4 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 4.8 years. The grant date fair value was estimated using the previous 20 days average trading price of our common stock.

In December 2012, we approved a new compensation plan for our directors. Our directors receive an annual retainer of $50,000, 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 $15,000 and the members of the Audit Committee (other than the Chairman) receive an annual retainer of $5,000, 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 $75,000, with the number of shares determined by the 60-day volume weighted average share price as of the day prior to the grant date.

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 statements of operations.

Predecessor recognized stock compensation expense of approximately $1.9 million and $8.0 million for the period from January 1, 2012 through August 31, 2012 and for the year ended December 31, 2011, respectively, which are included in general and administrative expenses. Under the terms of the Plan, 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 and for the year ended December 31, 2011 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		—		$	—			—	$	—

	Year Ended December 31, 2011
	Options			Weighted-Average Exercise Price			Weighted-Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding-beginning of year		160,800		$	72.60
Granted		—			—
Exercised		—			—
Expired		(10,500	)		(38.96	)
Outstanding-end of year		150,300		$	75.00			2.64 years	$	—
Exercisable-end of year		150,300		$	75.00			2.64 years	$	—

F-29

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 and for the year ended December 31, 2011 follows (in thousands accept 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		—		$	—			—	$	—

	Year Ended December 31, 2011
	Nonvested Stock			Weighted-Average Grant-Date Fair Value			Weighted-Average Remaining Contractual Term		Aggregate Intrinsic Value
Nonvested-beginning of year		734,376		$	15.27
Granted		598,836			5.92
Vested		(719,350	)		(11.74	)
Expired / Forfeited		(55,561	)		(36.22	)
Nonvested-end of year		558,301		$	7.45			0.48 years	$	3,307

(11) Income Taxes

Under the Plan, the Company’s 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 NOL’s 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. The Company’s NOLs have been reduced by approximately $230 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 place restrictions upon the ability of the equity interest holders to transfer their ownership in the Company. 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 continues to conclude 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 our net deferred tax assets at December 31, 2012.

As of December 31, 2012, our deferred tax assets exceeded deferred tax liabilities. Accordingly, based on significant recent operating losses other than the non-recurring taxable income resulting from the Contribution Agreement, and projections for future results, a valuation allowance has been recorded for our net deferred tax assets.

During the year ended December 31, 2011, the periods from January 1 through August 31, 2012, and the period from September 1 through December 31, 2012, no adjustments were recognized for uncertain tax benefits.

During 2013 and thereafter, we will continue to assess the realizability of its 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) attributable to income from continuing operations consisted of the following:

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012		Year Ended December 31, 2011
Current:
U.S.—Federal	$	—		$	—	$	—
U.S.—State		—			—		—
Foreign		—			—		—
Deferred:
U.S.—Federal		(2,757	)		—		(4,329	)
U.S.—State		—			—		—
Total	$	(2,757	)	$	—	$	(4,329	)

F-30

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

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Federal statutory rate		(35.0	)%		(35.0	)%		(35.0	)%
State income taxes, net of federal benefit		—			—			(1.9	)
Change in valuation allowance		(2.0	)		(33.0	)		34.3
Professional fees related to bankruptcy reorganization		8.0			17.0			1.8
Revenue from Wapiti Trust settlement		5			—			—
Cancellation of debt tax attribute reduction		—			51			—
Actual income tax rate		(24.0	)%		—	%		(0.8	)%

For the year ended December 31, 2011, the Predecessor recorded a tax benefit of $5.0 million due to a non-cash income tax benefit related to gains from discontinued oil and gas operations. U.S. GAAP requires all items be considered, including items recorded in discontinued operations, in determining the amount of tax benefit that results from a loss from continuing operations that should be allocated to continuing operations. In accordance with U.S. GAAP, we recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations.

Deferred tax assets (liabilities) are comprised of the following at December 31, 2012 and 2011 (in thousands):

	2012			2011
Deferred tax assets:
Net operating loss	$	450,195		$	450,632
Capital loss carry forwards		26,141			35,919
Asset retirement obligation		179			1,398
Property and equipment		23,045			39,912
Investment in Piceance Energy		45,172			—
Equity compensation		—			10,448
Equity investments		—			329
Derivative instruments		1,498			—
Minimum tax credit		785			1,045
Contribution carryforwards		189			517
Accrued bonuses		—			517
Allowance for doubtful accounts		—			93
Accrued vacation		—			125
Texadian Energy		326			—
Other		27			69
Total deferred tax assets		547,557			541,004
Valuation allowance		(544,442	)		(540,724	)
Net deferred tax assets	$	3,115		$	280
Deferred tax liabilities:
Property and equipment	$	—		$	—
Texadian Energy intangibles		3,083
Prepaid insurance, marketable securities and other		32			280
Total deferred tax liabilities	$	3,115		$	280
Total deferred taxes, net	$	—		$	—

F-31

We have net operating loss carryovers as of December 31, 2012 of $1,286 million 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, 2012 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 until we have utilized our net operating loss carry over.

(12) Earnings Per Share

Basic earnings per share (“EPS”) are 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, representing 9,592,125 shares (see Note 6 and 7). U.S. GAAP requires the inclusion of these Warrants in the calculation of basic EPS because they are issuable for minimal consideration. The following table sets forth the computation of basic and diluted earnings per share (in thousands, except per share amounts):

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Net loss attributable to common stockholders	$	(8,839	)	$	(45,437	)	$	(484,134	)
Gain from discontinued operations, net of tax		—			—			14,023
Net loss attributable to common stockholders	$	(8,839	)	$	(45,437	)	$	(470,111	)
Basic weighted-average common stock outstanding		157,335			28,841			28,841
Add: dilutive effects of stock options and unvested stock grants		—			—			—
Diluted weighted-average common stock outstanding		157,335			28,841			28,841
Basic loss per common share attributable to common stockholders:
Loss from continuing operations	$	(0.06	)	$	(1.57	)	$	(16.79	)
Discontinued operations		—			—			0.49
Net loss	$	(0.06	)	$	(1.57	)	$	(16.30	)
Diluted loss per common share attributable to common stockholders:
Loss from continuing operations	$	(0.06	)	$	(1.57	)	$	(16.79	)
Discontinued operations		—			—			0.49
Net loss	$	(0.06	)	$	(1.57	)	$	(16.30	)

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

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012		Year Ended December 31, 2011
Stock issuable upon conversion of convertible notes		—		379		379
Stock options		—		150		150
Non-vested restricted stock		—		558		558
Total potentially dilutive securities		—		1,087		1,087

(13) Predecessor Employee Benefits

The Predecessor adopted a profit sharing plan on January 1, 2002. All employees were eligible to participate and contributions to the profit sharing plan were voluntary and must be approved by the Board of Directors. Amounts contributed to the Plan vested over a six year service period.

The Predecessor adopted a 401(k) plan effective May 1, 2005. All employees are eligible to participate and make employee contributions once they have met the plan’s eligibility criteria. Under the 401(k) plan, the Predecessor’s employees make salary reduction contributions in accordance with the Internal Revenue Service guidelines. The Predecessor’s matching contribution was an

F-32

amount equal to 100% of the employee’s elective deferral contribution which cannot exceed 3% of the employee’s compensation, and 50% of the employee’s elective deferral which exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’s compensation. The expense recognized in relation to the 401(k) plan was $176,000 for 2011. The 401(k) matching contribution was suspended in April 2009, but was subsequently reinstated January 1, 2010.

(14) Segment Information

Following our acquisition of Texadian, we have two business segments, (i) natural gas and oil exploration and production and (ii) commodity transportation and marketing. For the period from September 1 through December 31, 2012, all of the operations as reported on our consolidated statement of operations related to oil and natural gas activities. For the period from September 1 through December 31, 2012, expenditures for long term assets, including goodwill and other intangible assets totaled approximately $415,000 for natural gas and oil activities and approximately $17.4 million for commodity transportation and marketing activities, respectively. At December 31, 2012, our reportable segment assets consisted of the following:

	Natural Gas and Oil Exploration and Production		Commodity Transportation and Marketing		Totals
Current assets	$	2,951	$	46,181	$	49,132
Net property and equipment		5,846		—		5,846
Investments in unconsolidated affiliates		104,434		—		104,434
Goodwill and other intangible assets		—		16,565		16,565
Assets held for sale		2,800		—		2,800
Other long term assets		3		8		11
Totals	$	116,034	$	62,754	$	178,788

Reconciliation of reportable segment assets to out consolidated totals is as follows (in thousands):

	December 31, 2012
Total assets for reportable segments	$	178,788
Cash and restricted cash not allocated to segments		10,617
Prepaid expenses		177
Total assets	$	189,582

(15) Disclosures About Capitalized Costs, Costs Incurred (Unaudited)

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

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012 (1)			Year Ended December 31, 2011
Company:
Unproved properties	$	—		$	84		$	72,081
Proved properties		4,804			759,755			688,521
		4,804			759,839			760,602
Accumulated depreciation and depletion		(337	)		(642,172	)		(442,169	)
	$	4,467		$	117,667		$	318,433
Company’s Share of Piceance Energy:
Unproved properties	$	16,180
Proved properties		134,638
		150,818
Accumulated depreciation and depletion		(2,808	)
	$	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 accounting (see Note 2).

F-33

Costs incurred in oil and gas activities are as follows (in thousands):

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012		Year Ended December 31, 2011
Company:
Unproved property acquisition costs	$	—	$	—	$	452
Proved property acquisition costs		—		—		(51	)
Development costs incurred on proved undeveloped reserves		—		1,613		4,858
Development costs—other		—		—		39,980
Exploration and dry hole costs		—		—		98
Total	$	—	$	1,613	$	45,337
Company’s Share of Piceance Energy:
Unproved properties acquisition costs	$	206
Proved properties acquisition costs (1)		32,519
Development costs incurred on proved undeveloped reserves		—
Development costs—other		291
Exploration and dry hole costs		—
Total	$	33,016

Included in costs incurred are asset retirement obligation costs for all periods presented.

(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-34

Changes in capitalized exploratory well costs are as follows (in thousands):

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Company:
Balance at beginning of year	$	—	$	8,770		$	6,200
Additions to capitalized exploratory well costs pending the determination of proved reserves		—		—			29,226
Exploratory well costs included in property divestitures		—		(8,770	)		—
Reclassified to proved oil and gas properties based on the determination of proved reserves		—		—			(26,656	)
Capitalized exploratory well costs charged to dry hole expense		—		—			—
Balance at end of year	$	—	$	—		$	8,770
Exploratory well costs capitalized for one year or less after completion of drilling	$	—	$	—		$	8,770
Exploratory well costs capitalized for greater than one year after completion of drilling		—		—			—
Balance at end of year	$	—	$	—		$	8,770
Company’s Share of Piceance Energy:
Balance at beginning of year	$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		—
Exploratory well costs included in property divestitures		—
Reclassified to proved oil and gas properties based on the determination of proved reserves		—
Capitalized exploratory well costs charged to dry hole expense		—
Balance at end of year	$	—
Exploratory well costs capitalized for one year or less after completion of drilling	$	—
Exploratory well costs capitalized for greater than one year after completion of drilling		—
Balance at end of year	$	—

The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same period.

F-35

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

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Company:
Revenue:
Oil and gas revenues	$	2,144	$	23,079		$	63,880
Expenses:
Production costs		1,688		16,980			29,157
Depletion and amortization		370		16,041			36,624
Exploration		—		2			338
Abandoned and impaired properties		—		151,347			419,851
Dry hole costs		—		—			355
Results of operations of oil and gas producing activities	$	86	$	(161,291	)	$	(422,445	)
Income from operations of properties sold, net	$	—	$	—		$	2,280
Gain on sale of properties		—		—			6,874
Income from results of discontinued operations of oil and gas producing activities	$	—	$	—		$	9,154
Company’s share of Piceance Energy:
Revenue:
Oil and gas revenues	$	6,464
Expenses:
Production costs		3,033
Depletion and amortization		2,808
Exploration		—
Abandoned and impaired properties		—
Dry hole costs		—
Results of operations of oil and gas producing activities	$	623
Total Company and Piceance Energy income from operations of oil and gas producing activities	$	709

F-36

(16) 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, reserves estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.

Proved Oil and Gas Reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices using the 12-month historical first of month average and costs as of the date the estimate was made for all years presented. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic productability is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves;” (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids that may occur in underlaid prospects; and (D) crude oil, natural gas, and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped oil and gas reserves are reserves 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved 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 tests in the area and in the same reservoir.

“Prepared” reserves are those quantities of reserves which were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of revenues which were estimated by the Company’s employees and audited by an independent petroleum consultant. An audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been determined using methods and procedures widely accepted within the industry and in accordance with SEC rules.

Estimates of the Company’s oil and natural gas reserves and present values as of December 31, 2012, August 31, 2012 and December 31, 2011 were prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers.

F-37

A summary of changes in estimated quantities of proved reserves for respective periods in 2012 and for the year ended December 31, 2011 is as follows:

	Gas (MMcf)			Oil (MBbl)			NGLS (MBb1)			Total (MMcfe)  (6)
Company:
Estimated Proved Reserves: Balance at December 31, 2010 (Predecessor)		122,679			1,920			—			134,199
Revisions of quantity estimate (1)		(20,795	)		(232	)		—			(22,187	)
Extensions and discoveries		—			—			—			—
Purchase of properties		—			—			—			—
Sale of properties (2)		(4,259	)		(983	)		—			(10,157	)
Production		(10,416	)		(211	)		—			(11,682	)
Estimated Proved Reserves: Balance at December 31, 2011 (Predecessor) (5)		87,209			494			—			90,173
Revisions of quantity estimate		—			85			—			512
Extensions and discoveries		—			—			—			—
Purchase of properties		—			—			—			—
Sale/disposition of properties (3)		(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
Extensions and discoveries		—			—			—			—
Purchase of properties		—			—			—			—
Sale of properties		—			—			—			—
Production		(10	)		(22	)		—			(139	)
Estimated Proved Reserves: Balance at December 31, 2012 (Successor)		446			286			—			2,163
Company’s Share of Piceance Energy:
Estimated Proved Reserves: Balance at September 1, 2012		—			—			—			—
Transfer from investees (4)		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
Purchase of properties		—			—			—			—
Sale of properties		—			—			—			—
Production		(1,391	)		(6	)		(48	)		(1,711	)
Estimated Proved Reserves: Balance at December 31, 2012		122,650			831			6,345			165,700
Total Estimated Proved Reserves: Balance at December 31, 2012		123,096			1,117			6,345			167,863
Proved Developed reserves
December 31, 2011		87,209			494			—			90,173
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
December 31, 2011		—			—			—			—
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

	CIG per Mbtu		WTI per Bbl
Base Pricing, before adjustments for contractual differentials:
December 31, 2011	$	3.99	$	83.33
August 31, 2012	$	2.75	$	90.85
December 31, 2012	$	2.56	$	91.21
December 31, 2012 – Piceance Energy	$	2.56	$	91.21

F-38

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.

⁽¹⁾  During 2011, negative revisions were related to limited capital to develop reserves.

⁽²⁾ During 2011, proved reserves located in Texas, Colorado, and Wyoming were sold in conjunction with the Wapiti Transaction.

⁽³⁾ 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).

⁽⁴⁾ 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 4).

⁽⁵⁾  At December 31, 2011, 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.

⁽⁶⁾  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, 2012			August 31, 2012			December 31, 2011
				(in thousands)
Company:
Future net cash flows	$	30,444		$	28,691		$	492,152
Future costs:
Production		20,596			19,973			252,532
Development and abandonment		319			319			319
Income taxes1		—			—			—
Future net cash flows		9,529			8,399			239,301
10% discount factor		(1,519	)		(1,176	)		(109,606	)
Standardized measure of discounted future net cash flows	$	8,010		$	7,223		$	129,695
Company’s Share of Piceance Energy:
Future net cash flows	$	568,706
Future costs:
Production		199,277
Development and abandonment		154,054
Income taxes1		—
Future net cash flows		215,375
10% discount factor		(143,416	)
Standardized measure of discounted future net cash flows	$	71,959
Total consolidated and equity investee interests in the standardized measure of discounted future net revenues	$	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.

F-39

The principal sources of changes in the standardized measure of discounted net cash flows for the respective periods during 2012 and for the year ended December 31, 2011 are as follows (in thousands):

	Successor									Predecessor
	Period from September 1, through December 31,			Company Share of Piceance Energy September 1, through December 31,			Total			Period from January 1, through August 31,			Year Ended December 31,
	2012			2012			2012			2012			2011
Beginning of the year										$	129,695		$	192,094
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	)		(42,187	)
Purchase of reserves in place		—			—			—			—			—
Net change in prices and production costs		(667	)		(139	)		(806	)		378			7,906
Changes in estimated future development costs		—			5			5			—			8,319
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	)		(17,130	)
Previously estimated development and abandonment costs incurred during the period		—			—			—			—			2,453
Sales/disposition of reserves in place		—			—			—			(118,104	)		(40,969	)
Change in future income tax		—			—			—			—			—
Other		258			4,360			4,618			—			—
Accretion of discount		241			1,842			2,083			8,647			19,209
													$	129,695
End of period	$	8,010		$	71,959		$	79,969		$	7,223

Reconciliation of PV-10 to Standardized Measure

PV-10 is the estimated present value of the future net revenues from our 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 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. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. 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, 2012 (in thousands):

	Company		Company Share of Piceance Energy		Total
PV-10	$	8,010	$	71,959	$	79,969
Present value of future income taxes discounted at 10%		—		—		—
Standardized measure of discounted future net cash flows	$	8,010	$	71,959	$	79,969

F-40

(17) Selected Quarterly Financial Data (Unaudited)

	Predecessor									Successor
	Quarter Ended						Period from July 1 through August 31			Month Ended September 30,			Quarter Ended December 31,
(in thousands)	March 31,			June 30,
Year Ended December 31, 2012
Total revenue	$	9,910		$	7,703		$	5,466		$	584		$	1,560
Loss from continuing operations		(8,121	)		(10,003	)		(158,910	)		(2,002	)		(6,837	)
Reorganization Items(1)		5,342			5,910			(142,848	)		—			—
Net loss		(13,463	)		(15,913	)		(16,062	)		(2,002	)		(6,837	)
Net income (loss) per common share:(1)
Basic	$	(0.46	)	$	(0.55	)	$	(0.56	)	$	(0.01	)	$	(0.05	)
Diluted	$	(0.46	)	$	(0.55	)	$	(0.56	)	$	(0.01	)	$	(0.05	)
Total Assets(2)	$	374,527		$	364,752		$	142,911		$	138,447		$	189,582
Total Equity(2)	$	37,779		$	22,745		$	109,562		$	107,560		$	100,757
Cash Flow from Operations(1)	$	(3,641	)	$	(9,513	)	$	(7,108	)	$	(347	)	$	(4,289	)
Cash Flow from Investing(1)	$	(679	)	$	327		$	72,974		$	—			(17,690	)
Cash Flow from Financing(1)	$	—		$	5,000		$	(65,340	)	$	2,000			21,629

(1) In preparing the December 31, 2012 financial statements, we recorded an immaterial correction of an error pursuant to FASB ASC Topic 250, Accounting Changes and Error Corrections. The error related to the presentation of the gain on settlement of liabilities and fresh start accounting through the statement of equity as of September 1, 2012. As a result of application of the provisions of FASB ASC Topic 852, Reorganizations, the effect of the reorganization should have been reflected in the statement of operations of the Predecessor for the period from July 1 through August 31, 2012. The effect of the reorganization was previously disclosed in the footnotes to the Form 10-Q for the period ended September 30, 2012 and the Company believes the correction of this error is not material to its previously issued Predecessor financial statements. The Company has adjusted certain balances within the statement of operations and cash flows to correct this presentation error as follows:

	Predecessor
	Period from July 1, 2012 Through August 31, 2012
	As reported			Adjustments			As Corrected
	(in thousands)
Statement of Operations
Loss from continuing operations before income taxes, reorganization items and discontinued operations	$	(158,910	)	$	—		$	(158,910	)
Reorganization items
Professional fees and administrative costs		(10,719	)		—			(10,719	)
Gain on settlement of liabilities		—			168,332			168,332
Fresh Start Adjustments		—			(14,765	)		(14,765	)
Net loss	$	(169,629	)	$	153,567		$	(16,062	)
Cash Flow Data
Cash flow used in operations	$	(4,709	)	$	(2,399	)	$	(7,108	)
Cash flow provided by investing activities		(1,193	)		74,167			72,974
Cash flow used in financing activities		3,500			(68,840	)		(65,340	)

(2) Reflects true-up adjustments to the preliminary fresh start accounting values recorded at September 30, 2012.

	Predecessor
	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share amounts)
Year Ended December 31, 2011 (Predecessor)
Total revenue	$	17,715		$	16,882		$	16,546		$	12,737
Loss from continuing operations before income taxes, discontinued operations and cumulative effect		(27,424	)		(12,724	)		(429,973	)		(17,411	)
Net loss		(27,841	)		(963	)		(429,430	)		(11,877	)
Net income (loss) per common share:(1)
Basic	$	(1.00	)	$	(0.03	)	$	(15.40	)	$	(0.43	)
Diluted	$	(1.00	)	$	(0.03	)	$	(15.40	)	$	(0.43	)

F-41

(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 6).

(19) Subsequent Events

On January 17, 2013, we drew an additional $8.0 million on our Loan Agreement to support Texadian’s working capital requirements. On February 20, 2013, we sold our compressors that were classified for sale for $2.8 million. Through March 25, 2013, we have issued 1,469,575 shares of our common stock to settle various bankruptcy claims.

F-42

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 27^th day of March, 2013.

PAR PETROLEUM CORPORATION
By:	/s/ John T. Young, Jr.
	John T. Young, Jr., Chief Executive Officer
By:	/s/ R. Seth Bullock
	R. Seth Bullock, 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/ John T. Young, Jr.	March 27, 2013
John T. Young, Jr., Chief Executive Officer (Principal Executive Officer)
/s/ R. Seth Bullock	March 27, 2013
R. Seth Bullock, Chief Financial Officer (Principal Financial and Accounting Officer)
/s/ Jacob Mercer	March 27, 2013
Jacob Mercer, Director
/s/ William Monteleone	March 27, 2013
William Monteleone, Director
/s/ Benjamin Lurie	March 27, 2013
Benjamin Lurie, Director
/s/ Michael Keener	March 27, 2013
Michael Keener, Director
/s/ L. Melvin Cooper	March 27, 2013
L. Melvin Cooper, Director

EX-10.2

Exhibit 10.2

Execution Version

FIRST AMENDMENT TO DELAYED DRAW TERM LOAN CREDIT AGREEMENT

FIRST AMENDMENT TO DELAYED DRAW TERM LOAN CREDIT AGREEMENT (this “Amendment”), dated as of September 28, 2012 by and among Par Petroleum Corporation, a Delaware corporation (the “Borrower”), the Guarantors party thereto (the “Guarantors” and together with the Borrower, each a “Credit Party” and collectively, the “Credit Parties”), and the undersigned Lenders party hereto.

WHEREAS, the Credit Parties, Jefferies Finance LLC, as administrative agent, and the Lenders party thereto from time to time entered into that certain Delayed Draw Term Loan Credit Agreement dated as of August 31, 2012 (as may be amended, amended and restated, modified, supplemented, extended, renewed, restated or replaced from time to time, the “Credit Agreement”);

WHEREAS, on the Plan Effective Date, Amber Resources, Inc. became a wholly-owned Subsidiary of the Borrower as provided in the Plan of Reorganization;

WHEREAS, the Borrower has requested that the Requisite Lenders agree to amend certain provisions of the Credit Agreement; and

WHEREAS, the Borrower, the Guarantors, and the Requisite Lenders have agreed to so amend the Credit Agreement subject to the terms and conditions set forth herein.

NOW, THEREFORE, in consideration of the mutual promises contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

1. Defined Terms. All capitalized terms used herein (including the recitals hereto) shall have the respective meaning assigned to such terms in the Credit Agreement, unless otherwise defined herein.

2. Amendments to Credit Agreement.

(a) Section 5.8 of the Credit Agreement is hereby amended by deleting clause (ii) thereof in its entirety and substituting the phrase “(ii) Intentionally Omitted” in lieu thereof.

(b) Section 5.12(b) of the Credit Agreement is hereby amended by deleting the phrase “or Amber Resources” in the first parenthetical of clause (i) thereof.

(c) The definition of “Immaterial Subsidiary” in Appendix I of the Credit Agreement is hereby amended by inserting the phrase “Amber Resources,” in the first sentence thereof immediately after the phrase “means each of”.

3. Representations and Warranties. The Borrower and the Guarantors hereby confirm, reaffirm and restate the representations and warranties made by them in the Credit Agreement, as amended hereby, and confirms that all such representations and warranties are true and correct in all material respects as of the date hereof. The Borrower and each Guarantor further represent and warrant (which representations and warranties shall survive the execution and delivery of this Amendment) to the Lenders that:

(a) The execution, delivery, and performance by each Credit Party of this Amendment and the consummation of the transactions contemplated hereby, (i) are within such Credit Party’s governing powers, (ii) have been duly authorized by all necessary governing action, (iii) do not contravene (x) such Credit Party’s Organizational Documents or (y) any law or any contractual restriction binding on or affecting such Credit Party, and (d) will not result in or require the creation or imposition of any Lien prohibited by the Loan Documents;

(b) No consent, order, authorization, or approval or other action by, and no notice to or filing with, any Governmental Authority or any other Person is required for the due execution, delivery, and performance by any Credit Party of this Amendment, or the consummation of the transactions contemplated hereby, except for those consents and approvals that have been obtained or made on or prior to the date hereof and that are in full force and effect;

(c) This Amendment has been duly executed and delivered by such Credit Party and is the legal, valid, and binding obligation of each Credit Party enforceable against such Credit Party in accordance with its terms, except as such enforceability may be limited by any applicable bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance or transfer, or similar law affecting creditors’ rights generally and by general principles of equity;

(d) No Default or Event of Default has occurred and is continuing;

(e) Amber Resources is a wholly-owned Subsidiary of Borrower as provided in the Plan of Reorganization; and

(f) Amber Resources owns no Property other than immaterial Property and no Credit Party is directly or indirectly responsible for any Debt of or has any obligation to provide credit support or to maintain or preserve Amber Resources’ financial condition or to cause Amber Resources to achieve any specified levels of operating results.

4. Effect of this Amendment. Except as expressly amended hereby, the Credit Agreement and the other Loan Documents are ratified and confirmed in all respects and shall remain in full force and effect in accordance with their respective terms. The terms of this Amendment shall not be deemed (i) a waiver of any Default or Event of Default, (ii) a consent, waiver or modification with respect to any term, condition, or obligation of the Borrower or any other Credit Party in the Credit Agreement or any other Loan Document except as expressly set forth above, (iii) a consent, waiver or modification with respect to any other event, condition (whether now existing or hereafter occurring) or provision of the Loan Documents or (iv) to prejudice any right or remedy which the Administrative Agent or any Lender may now or in the future have under or in connection with the Credit Agreement or any other Loan Document.

5. Conditions Precedent. This Amendment shall become effective when, and only when, the Requisite Lenders shall have executed this Amendment and received counterparts of this Amendment, duly executed by the Borrower and each Guarantor.

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6. Miscellaneous.

(a) Survival of Representations and Warranties. All representations and warranties made in this Amendment or any other document furnished in connection with this Amendment shall survive the execution and delivery of this Amendment and such other documents, and no investigation by the Administrative Agent or the Lenders or any closing of any transaction shall affect the representations and warranties or the right of the Administrative Agent or the Lenders to rely upon them.

(b) Notices. All notices required to be made under this Amendment shall be made in the manner and at the address set forth in Section 10.2 of the Credit Agreement.

(c) Expenses. The Borrower agrees to pay or reimburse the Lenders for all its reasonable fees and out-of-pocket disbursements incurred by the Lenders in connection with the preparation, execution, delivery, administration and enforcement of this Amendment, including without limitation the reasonable fees and disbursements of counsel for the Lenders, to the same extent that the Borrower would be required to do so pursuant to Section 10.4 of the Credit Agreement.

(d) Reference to Credit Agreement. From and after the effectiveness of this Amendment, all references to the Credit Agreement shall mean the Credit Agreement as amended hereby and as hereafter modified, amended, restated or supplemented from time to time, and each reference in any other Loan Document to the Credit Agreement shall mean the Credit Agreement as amended hereby and as hereafter modified, amended, restated or supplemented from time to time. The Amendment shall constitute a Loan Document under the Credit Agreement for all purposes.

(e) Severability. Any provision of this Amendment held by a court of competent jurisdiction to be invalid or unenforceable, such provision shall be inapplicable to the extent of such invalidity without affecting the validity or enforceability of the remainder of this Amendment and the effect thereof shall be confined to the provision so held to be invalid or unenforceable.

(f) Section Headings. Section headings herein are included for convenience of reference only and shall not affect the meaning or interpretation of this Amendment.

(g) Entire Agreement. This Amendment shall be deemed to be a Loan Document and, together with the other Loan Documents and the agreements, documents and instruments contemplated hereby, constitutes the entire understanding of the parties with respect to the subject matter hereof and thereof, and any other prior or contemporaneous agreements, whether written or oral, with respect hereto or thereto are expressly superseded hereby and thereby.

(h) Counterparts. This Amendment may be executed in any number of counterparts and by different parties on separate counterparts, each of which, when executed and delivered, shall be deemed to be an original, and all of which, when taken together, shall constitute but one and the same Amendment. Delivery of an executed counterpart of this Amendment by facsimile or .pdf shall be equally as effective as delivery of an original executed

3

counterpart of this Amendment. Any party delivering an executed counterpart of this Amendment by facsimile or .pdf also shall deliver an original executed counterpart of this Amendment but the failure to deliver an original executed counterpart shall not affect the validity, enforceability, and binding effect of this Amendment.

(i) Successors and Assigns. This Agreement shall be binding on and inure to the benefit of the parties hereto and their heirs, beneficiaries, successors and assigns. The Credit Parties may not assign this Amendment or any of their respective rights or obligations hereunder to any Person without the prior written consent of the Requisite Lenders, which consent may be withheld or given in each such Lender’s sole discretion.

(j) Governing Law; Venue; Jury Trial. THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE CHOICE OF LAW AND VENUE PROVISIONS SET FORTH IN SECTION 10.12 OF THE CREDIT AGREEMENT, AND SHALL BE SUBJECT TO THE JURY TRIAL WAIVER SET FORTH IN SECTION 10.14 OF THE CREDIT AGREEMENT.

(k) Guarantors. Each Guarantor, for value received, hereby expressly consents and agrees to the Borrower’s execution and delivery of this Amendment, and to the performance by the Borrower of its agreements and obligations hereunder. This Amendment and the performance or consummation of any transaction or matter contemplated under this Amendment, shall not limit, restrict, extinguish or otherwise impair any Guarantor’s liability to the Administrative Agent and Lenders with respect to the payment and other performance obligations of such Guarantor pursuant to the Guarantees. Each Guarantor hereby ratifies, confirms and approves its Guarantee and acknowledges that it is unconditionally liable to the Administrative Agent and Lenders for the full and timely payment of the Guaranteed Obligations (on a joint and several basis with the other Guarantors). Each Guarantor hereby acknowledges that it has no defenses, counterclaims or set-offs with respect to the full and timely payment of any or all Guaranteed Obligations.

[Remainder of Page Intentionally Left Blank]

4

IN WITNESS WHEREOF, each of the parties hereto has duly executed this First Amendment to Delayed Draw Term Loan Credit Agreement as of the date first written above.

BORROWER: PAR PETROLEUM CORPORATION, a Delaware corporation
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
GUARANTORS: PAR PICEANCE ENERGY EQUITY LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
PAR UTAH LLC, a Delaware limited liability company By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
EWI LLC, a Delaware limited liability company By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer

[Signature Page to First Amendment to Delayed Draw Term Loan Credit Agreement]

PAR WASHINGTON LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
PAR NEW MEXICO LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
HEWW EQUIPMENT LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
PAR POINT ARGUELLO LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer

[Signature Page to First Amendment to Delayed Draw Term Loan Credit Agreement]

REQUISITE LENDERS:
WB DELTA, LTD., as a Lender
By:	/s/ Mark Strefling
Name:	Mark Strefling
Title:	Director

[Signature Page to First Amendment to Delayed Draw Term Loan Credit Agreement]

ZCOF PAR PETROLEUM HOLDINGS, L.L.C., as a Lender
By:	/s/ Philip G. Tinkler
Name:	Philip G. Tinkler
Title:	Vice President

[Signature Page to First Amendment to Delayed Draw Term Loan Credit Agreement]

EX-10.3

Exhibit 10.3

WAIVER AND SECOND AMENDMENT TO DELAYED

DRAW TERM LOAN CREDIT AGREEMENT

WAIVER AND SECOND AMENDMENT TO DELAYED DRAW TERM LOAN CREDIT AGREEMENT (this “Amendment”), dated as of November 29, 2012 by and among Par Petroleum Corporation, a Delaware corporation (the “Borrower”), the Guarantors party hereto (the “Guarantors” and together with the Borrower, each a “Credit Party” and collectively, the “Credit Parties”), and the undersigned Lenders party hereto.

WHEREAS, the Credit Parties, Jefferies Finance LLC, as administrative agent, and the Lenders party thereto from time to time entered into that certain Delayed Draw Term Loan Credit Agreement dated as of August 31, 2012, as amended on September 28, 2012 (as may be amended, amended and restated, modified, supplemented, extended, renewed, restated or replaced from time to time, the “Credit Agreement”);

WHEREAS, on October 15, 2012, the Credit Parties changed the location of their chief executive office without providing prior written notice to the Lenders as required under Section 5.17 of the Credit Agreement and to the JV Company Credit Facility Agent as required under Section 3.3(b) of the Parent Pledge Agreement, and, as a result, Events of Default under Sections 7.1(c) and (d) of the Credit Agreement (the “Existing Defaults”) have occurred and are continuing;

WHEREAS, pursuant to Section 5.18 of the Credit Agreement, the Credit Parties are required to liquidate or dissolve each Immaterial Subsidiary no later than 90 days after the Closing Date;

WHEREAS, on November 13, 2012, the Credit Parties motioned the Bankruptcy Court to enter an order permitting the dissolution of the Immaterial Subsidiaries pursuant to the Plan of Reorganization without requiring further action by their Boards of Directors, which motion is set for hearing by the Bankruptcy Court on December 4, 2012;

WHEREAS, the Borrower has requested that the Requisite Lenders agree to amend certain provisions of the Credit Agreement; and

WHEREAS, the Borrower, the Guarantors, and the Requisite Lenders have agreed to so amend the Credit Agreement subject to the terms and conditions set forth herein.

NOW, THEREFORE, in consideration of the mutual promises contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

1. Defined Terms. All capitalized terms used herein (including the recitals hereto) shall have the respective meaning assigned to such terms in the Credit Agreement, unless otherwise defined herein.

2. Limited Waiver.

a) Each Credit Party hereby acknowledges and agrees that the Existing Defaults have occurred, and are continuing and cannot be cured by it, and have not previously been waived by the Lenders.

b) Notwithstanding anything to the contrary in the Credit Agreement or any other Loan Document, but subject to the satisfaction of the conditions precedent set forth in Section 6 below, the Lenders hereby waive the Existing Defaults as of the Waiver Effective Time (as defined below).

c) The limited waiver contained in Section 2(b) is and shall be effective solely for the specific instances and purposes described herein and shall not constitute a waiver of any other Default or Event of Default (whether now arising or hereafter occurring) or term, provision or condition of the Credit Agreement or any other Loan Document or to any other obligations of the Borrower or any other Credit Party. The Lenders’ entry into this Agreement shall not obligate or commit the Lenders to provide any other consents or waivers under the Credit Agreement or the other Loan Documents in the future, whether for purposes similar to those described herein or otherwise. Any such consents or waivers may be granted by the Lenders in their sole discretion.

3. Amendments to Credit Agreement. As of the Amendment Effective Time (as defined below):

(a) Section 5.18 of the Credit Agreement is hereby amended by deleting the first sentence thereof in its entirety and inserting the following in lieu thereof:

On or before December 31, 2012 (or such later date as agreed by the Requisite Lenders in their sole discretion), the Credit Parties shall take all actions required of the Credit Parties under applicable law to liquidate or dissolve each Immaterial Subsidiary and thenceforth shall diligently continue to pursue the liquidation or dissolution of the Immaterial Subsidiaries and shall take all commercially reasonable action necessary or advisable to effectuate such liquidation or dissolution, as applicable; provided, that the Credit Parties shall not be deemed to be in breach of this Section 5.18 solely as a result of any delay of any applicable Governmental Authority in approving or effecting such liquidation or dissolution so long as the Credit Parties shall have diligently pursued such liquidation or dissolution and taken all commercially reasonable action necessary or advisable to effectuate such liquidation or dissolution, as applicable; provided, further, that the Credit Parties shall promptly after December 31, 2012 comply with Section 5.12(b) with respect to any Immaterial Subsidiary with respect to which the Credit Parties have not taken all such action on or before December 31, 2012 unless the Board of Directors of the Borrower shall determine that such

2

Immaterial Subsidiary does not own any material Property and that the value of such Immaterial Subsidiary’s Property would make compliance with Section 5.12(b) impractical or uneconomic, and the Borrower shall have so notified the Administrative Agent and the Lenders in writing.

(b) Schedule II of the Credit Agreement is hereby amended by deleting the notice address for the Borrower and the other Credit Parties set forth therein and inserting the following, which shall be the address of each Credit Party’s chief executive office for all purposes under the Loan Documents, in lieu thereof:

1301 McKinney, Suite 2025

Houston, Texas 77010

Attn: John T. Young, Jr., Chief Executive Officer

T: (713) 969-3293

F: (713) 650-0502

E: jyoung@conwaymackenzie.com

4. Representations and Warranties. The Borrower and the Guarantors hereby confirm, reaffirm and restate the representations and warranties made by them in the Credit Agreement, as amended hereby, and confirm that all such representations and warranties are true and correct in all material respects as of the date hereof. The Borrower and each Guarantor further represent and warrant (which representations and warranties shall survive the execution and delivery of this Amendment) to the Lenders that:

(a) The execution, delivery, and performance by each Credit Party of this Amendment and the consummation of the transactions contemplated hereby, (i) are within such Credit Party’s governing powers, (ii) have been duly authorized by all necessary governing action, (iii) do not contravene (x) such Credit Party’s Organizational Documents or (y) any law or any contractual restriction binding on or affecting such Credit Party, and (iv) will not result in or require the creation or imposition of any Lien prohibited by the Loan Documents;

(b) No consent, order, authorization, or approval or other action by, and no notice to or filing with, any Governmental Authority or any other Person is required for the due execution, delivery, and performance by any Credit Party of this Amendment, or the consummation of the transactions contemplated hereby, except for those consents and approvals that have been obtained or made on or prior to the date hereof and that are in full force and effect;

(c) This Amendment has been duly executed and delivered by such Credit Party and is the legal, valid, and binding obligation of each Credit Party enforceable against such Credit Party in accordance with its terms, except as such enforceability may be limited by any applicable bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance or transfer, or similar law affecting creditors’ rights generally and by general principles of equity;

(d) No Default or Event of Default (other than the Existing Defaults) has occurred and is continuing; and

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(e) Each Immaterial Subsidiary owns no Property other than immaterial Property and no Credit Party is directly or indirectly responsible for any Debt of or has any obligation to provide credit support or to maintain or preserve any such Immaterial Subsidiary’s financial condition or to cause such Immaterial Subsidiary to achieve any specified levels of operating results.

5. Effect of this Amendment. Except as expressly amended hereby, the Credit Agreement and the other Loan Documents are ratified and confirmed in all respects and shall remain in full force and effect in accordance with their respective terms. Except as expressly set forth herein, the terms of this Amendment shall not be deemed (i) a waiver of any Default or Event of Default, (ii) a consent, waiver or modification with respect to any term, condition, or obligation of the Borrower or any other Credit Party in the Credit Agreement or any other Loan Document except as expressly set forth above, (iii) a consent, waiver or modification with respect to any other event, condition (whether now existing or hereafter occurring) or provision of the Loan Documents or (iv) to prejudice any right or remedy which the Administrative Agent or any Lender may now or in the future have under or in connection with the Credit Agreement or any other Loan Document.

6. Conditions Precedent.

(a) To Effectiveness of this Amendment. This Amendment (subject to Section 6(b) below with respect to the limited waiver provided in Section 2(b) hereof) shall become effective when, and only when, the Requisite Lenders shall have executed this Amendment and received counterparts of this Amendment, duly executed by the Borrower and each Guarantor (the time when such condition shall have been satisfied, provided for or waived to the Requisite Lenders’ satisfaction, the “Amendment Effective Time”).

(b) To Effectiveness of Limited Waiver. The limited waiver provided in Section 2(b) hereof shall become effective when, and only when, (i) the Amendment Effective Time shall have occurred, and (ii) the Requisite Lenders shall have received evidence reasonably acceptable to them in their sole discretion that the requisite JV Company Credit Facility Lenders have waived any defaults or events of default under the JV Company Credit Agreement that may have resulted from the JV Holding Sub’s failure to give notice of the relocation of its chief executive office as required in the Parent Pledge Agreement (the time when such conditions have been satisfied, provided for or waived to the Requisite Lenders’ satisfaction, the “Waiver Effective Time”). The Requisite Lenders authorize the Borrower to rely upon the confirmation by Brown Rudnick LLP that the Waiver Effective Time has occurred.

7. Miscellaneous.

(a) Survival of Representations and Warranties. All representations and warranties made in this Amendment or any other document furnished in connection with this Amendment shall survive the execution and delivery of this Amendment and such other documents, and no investigation by the Administrative Agent or the Lenders or any closing of any transaction shall affect the representations and warranties or the right of the Administrative Agent or the Lenders to rely upon them.

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(b) Notices. All notices required to be made under this Amendment shall be made in the manner and at the address set forth in Section 10.2 of the Credit Agreement.

(c) Expenses. The Borrower agrees to pay or reimburse the Lenders for all its reasonable fees and out-of-pocket disbursements incurred by the Lenders in connection with the preparation, execution, delivery, administration and enforcement of this Amendment, including without limitation the reasonable fees and disbursements of counsel for the Lenders, to the same extent that the Borrower would be required to do so pursuant to Section 10.4 of the Credit Agreement.

(d) Reference to Credit Agreement. From and after the Amendment Effective Time, all references to the Credit Agreement shall mean the Credit Agreement as amended hereby and as hereafter modified, amended, restated or supplemented from time to time, and each reference in any other Loan Document to the Credit Agreement shall mean the Credit Agreement as amended hereby and as hereafter modified, amended, restated or supplemented from time to time. The Amendment shall constitute a Loan Document under the Credit Agreement for all purposes.

(e) Severability. Any provision of this Amendment held by a court of competent jurisdiction to be invalid or unenforceable, such provision shall be inapplicable to the extent of such invalidity without affecting the validity or enforceability of the remainder of this Amendment and the effect thereof shall be confined to the provision so held to be invalid or unenforceable.

(f) Section Headings. Section headings herein are included for convenience of reference only and shall not affect the meaning or interpretation of this Amendment.

(g) Entire Agreement. This Amendment shall be deemed to be a Loan Document and, together with the other Loan Documents and the agreements, documents and instruments contemplated hereby, constitutes the entire understanding of the parties with respect to the subject matter hereof and thereof, and any other prior or contemporaneous agreements, whether written or oral, with respect hereto or thereto are expressly superseded hereby and thereby.

(h) Counterparts. This Amendment may be executed in any number of counterparts and by different parties on separate counterparts, each of which, when executed and delivered, shall be deemed to be an original, and all of which, when taken together, shall constitute but one and the same Amendment. Delivery of an executed counterpart of this Amendment by facsimile or .pdf shall be equally as effective as delivery of an original executed counterpart of this Amendment. Any party delivering an executed counterpart of this Amendment by facsimile or .pdf also shall deliver an original executed counterpart of this Amendment but the failure to deliver an original executed counterpart shall not affect the validity, enforceability, and binding effect of this Amendment.

(i) Successors and Assigns. This Agreement shall be binding on and inure to the benefit of the parties hereto and their heirs, beneficiaries, successors and assigns. The Credit Parties may not assign this Amendment or any of their respective rights or obligations hereunder to any Person without the prior written consent of the Requisite Lenders, which consent may be withheld or given in each such Lender’s sole discretion.

5

(j) Governing Law; Venue; Jury Trial. THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE CHOICE OF LAW AND VENUE PROVISIONS SET FORTH IN SECTION 10.12 OF THE CREDIT AGREEMENT, AND SHALL BE SUBJECT TO THE JURY TRIAL WAIVER SET FORTH IN SECTION 10.14 OF THE CREDIT AGREEMENT.

(k) Guarantors. Each Guarantor, for value received, hereby expressly consents and agrees to the Borrower’s execution and delivery of this Amendment, and to the performance by the Borrower of its agreements and obligations hereunder. This Amendment and the performance or consummation of any transaction or matter contemplated under this Amendment, shall not limit, restrict, extinguish or otherwise impair any Guarantor’s liability to the Administrative Agent and Lenders with respect to the payment and other performance obligations of such Guarantor pursuant to the Guarantees. Each Guarantor hereby ratifies, confirms and approves its Guarantee and acknowledges that it is unconditionally liable to the Administrative Agent and Lenders for the full and timely payment of the Guaranteed Obligations (on a joint and several basis with the other Guarantors). Each Guarantor hereby acknowledges that it has no defenses, counterclaims or set-offs with respect to the full and timely payment of any or all Guaranteed Obligations.

[Remainder of Page Intentionally Left Blank]

6

IN WITNESS WHEREOF, each of the parties hereto has duly executed this Second Amendment to Delayed Draw Term Loan Credit Agreement as of the date first written above.

BORROWER:
PAR PETROLEUM CORPORATION, a Delaware corporation
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
GUARANTORS:
PAR PICEANCE ENERGY EQUITY LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
PAR UTAH LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
EWI LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer

[Signature Page to Second Amendment to Delayed Draw Term Loan Credit Agreement]

PAR WASHINGTON LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
PAR NEW MEXICO LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
HEWW EQUIPMENT LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer
PAR POINT ARGUELLO LLC, a Delaware limited liability company
By: PAR PETROLEUM CORPORATION, a Delaware corporation, its Sole Member
By:	/s/ John T. Young, Jr.
Name:	John T. Young, Jr.
Title:	Chief Executive Officer

[Signature Page to Second Amendment to Delayed Draw Term Loan Credit Agreement]

REQUISITE LENDERS:
WB DELTA, LTD., as a Lender
By:	/s/ Mark Strefling
Name:	Mark Strefling
Title:	Director

[Signature Page to Second Amendment to Delayed Draw Term Loan Credit Agreement]

ZCOF PAR PETROLEUM HOLDINGS, L.L.C., as a Lender
By:	/s/ Philip G. Tinkler
Name:	Philip G. Tinkler
Title:	Vice President

[Signature Page to Second Amendment to Delayed Draw Term Loan Credit Agreement]

EX-21.1

Exhibit 21.1

Subsidiaries of the Registrant

1) Par Piceance Energy Equity, LLC – Delaware

2) Texadian Energy, Inc. – Delaware

3) Par Point Arguello, LLC – Delaware

4) EWI, LLC – Delaware

5) Par Washington, LLC – Delaware

6) Par Utah, LLC – Delaware

7) Par New Mexico, LLC – Delaware

8) HEWW Equipment, LLC – Delaware

9) Texadian Energy Canada Limited – Alberta, Canada

10) Piceance Energy, LLC – Delaware

11) Castle Exploration Company Inc. – Pennsylvania

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the registration statement on Form S-8 (Registration No. 333-185612) of Par Petroleum of our report dated March 27, 2013, with respect to the consolidated balance sheet of Par Petroleum Corporation as of December 31, 2012 and the consolidated statements of operations, changes in equity and cash flows for the period from September 1, 2012 through December 31, 2012, appearing in the Annual Report on Form 10-K of Par Petroleum Corporation.

/s/ EKS&H LLLP

EKS&H LLLP

Denver, Colorado

March 27, 2013

EX-23.2

Exhibit 23.2

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) of Par Petroleum Corporation (formerly Delta Petroleum Corporation) and subsidiaries (the Predecessor) of our report dated March 27, 2013, with respect to the consolidated balance sheet of the Predecessor as of December 31, 2011, and the related consolidated statements of operations (Predecessor), changes in equity (Predecessor), and cash flows (Predecessor) for the period January 1, 2012 through August 31, 2012 and for the year ended December 31, 2011, which report appears in the December 31, 2012 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 27, 2013

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the incorporation by reference in the registration statement on Form S-8 (Registration No. 333-185612) and to the inclusion in this Annual Report on Form 10-K of Par Petroleum Corporation of our report dated February 21, 2013, with respect to estimates of proved reserves attributable to certain interests of Par Petroleum Corporation as of December 31, 2012.

NETHERLAND, SEWELL & ASSOCIATES, INC.
	By:	/s/ Phillip S. (Scott) Frost
		Phillip S. (Scott) Frost
		Senior Vice President

Dallas, Texas

March 26, 2013

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 CHIEF EXECUTIVE OFFICER

Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, John T. Young, Jr., 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 27, 2013

/s/ John T. Young, Jr.

John T. Young, Jr.

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, R. Seth Bullock, 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 27, 2013

/s/ R. Seth Bullock

R. Seth Bullock

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned, John T. Young, Jr., Chief Executive Officer of Par Petroleum Corporation (the “Company”), certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1. The Annual Report on Form 10-K of the Company for the year ended December 31, 2012 (“the Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; 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/ John T. Young, Jr.

John T. Young, Jr.

Chief Executive Officer

Date: March 27, 2013

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned, R. Seth Bullock, Chief Financial Officer of Par Petroleum Corporation (the “Company”), certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1. The Annual Report on Form 10-K of the Company for the year ended December 31, 2012 (“the Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; 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/ R. Seth Bullock

R. Seth Bullock

Chief Financial Officer

Date: March 27, 2013

EX-99.1

Exhibit 99.1

February 21, 2013

Mr. R. Seth Bullock

Par Petroleum Corporation

1301 McKinney Street, Suite 2025

Houston, Texas 77010

Dear Mr. Bullock:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2012, 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, 2012, to be:

	Net Reserves						Future Net Revenue (M$)
	Oil		NGL		Gas				Present Worth
Category	(MBBL)		(MBBL)		(MMCF)		Total		at 10%
Proved Developed Producing		427.0		1,420.3		31,205.5		71,442.0		47,055.4
Proved Developed Non-Producing		96.1		832.2		17,633.3		39,149.6		13,039.1
Proved Undeveloped		593.5		4,092.0		74,257.0		114,312.2		19,874.9
Total Proved		1,116.6		6,344.6		123,095.8		224,903.8		79,969.4

Totals may not add because of rounding.

The oil reserves 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. There are no probable or possible reserves at the price and cost parameters used in this report. 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 2012. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.21 per barrel is adjusted by lease for quality, transportation fees, and local price differentials. For gas volumes, the average CIG Rocky Mountains spot price of $2.563 per MMBTU is used for the Colorado properties and the average Henry Hub spot price of $2.757 per MMBTU is used for the New Mexico properties. These average regional spot prices are adjusted by lease for energy content, transportation fees, and local 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 $85.87 per barrel of oil, $34.66 per barrel of NGL, and $2.302 per MCF of gas. By area, these average adjusted prices are $104.16 per barrel of oil for the California properties; $79.71 per barrel of oil, $34.66 per barrel of NGL, and $2.301 per MCF of gas for the Colorado properties; and $88.17 per barrel of oil and $4.581 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. Since all properties are nonoperated, headquarters general and administrative overhead expenses of Par are not included. Operating costs are held constant throughout the lives of the properties.

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 California properties. For the California properties, abandonment costs used in this report are Par’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. Capital costs and abandonment costs are held constant to the date of expenditure.

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 gas 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 gas 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. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. 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: February 21, 2013		Date Signed: February 21, 2013

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%

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)

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.

(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:

• 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);

• The company’s historical record at completing development of comparable long-term projects;

• The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

• 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

• 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

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Disclosures About Capitalized Costs, Costs Incurred (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Capitalized Costs Related to Oil and Gas Activities

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

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012 (1)			Year Ended December 31, 2011
Company:
Unproved properties	$	—		$	84		$	72,081
Proved properties		4,804			759,755			688,521
		4,804			759,839			760,602
Accumulated depreciation and depletion		(337	)		(642,172	)		(442,169	)
	$	4,467		$	117,667		$	318,433
Company’s Share of Piceance Energy:
Unproved properties	$	16,180
Proved properties		134,638
		150,818
Accumulated depreciation and depletion		(2,808	)
	$	148,010

Costs Incurred in Oil and Gas Activities

Costs incurred in oil and gas activities are as follows (in thousands):

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012		Year Ended December 31, 2011
Company:
Unproved property acquisition costs	$	—	$	—	$	452
Proved property acquisition costs		—		—		(51	)
Development costs incurred on proved undeveloped reserves		—		1,613		4,858
Development costs—other		—		—		39,980
Exploration and dry hole costs		—		—		98
Total	$	—	$	1,613	$	45,337
Company’s Share of Piceance Energy:
Unproved properties acquisition costs	$	206
Proved properties acquisition costs (1)		32,519
Development costs incurred on proved undeveloped reserves		—
Development costs—other		291
Exploration and dry hole costs		—
Total	$	33,016

Included in costs incurred are asset retirement obligation costs for all periods presented.

(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.

Changes in Capitalized Exploratory Well Costs

Changes in capitalized exploratory well costs are as follows (in thousands):

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Company:
Balance at beginning of year	$	—	$	8,770		$	6,200
Additions to capitalized exploratory well costs pending the determination of proved reserves		—		—			29,226
Exploratory well costs included in property divestitures		—		(8,770	)		—
Reclassified to proved oil and gas properties based on the determination of proved reserves		—		—			(26,656	)
Capitalized exploratory well costs charged to dry hole expense		—		—			—
Balance at end of year	$	—	$	—		$	8,770
Exploratory well costs capitalized for one year or less after completion of drilling	$	—	$	—		$	8,770
Exploratory well costs capitalized for greater than one year after completion of drilling		—		—			—
Balance at end of year	$	—	$	—		$	8,770
Company’s Share of Piceance Energy:
Balance at beginning of year	$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		—
Exploratory well costs included in property divestitures		—
Reclassified to proved oil and gas properties based on the determination of proved reserves		—
Capitalized exploratory well costs charged to dry hole expense		—
Balance at end of year	$	—
Exploratory well costs capitalized for one year or less after completion of drilling	$	—
Exploratory well costs capitalized for greater than one year after completion of drilling		—
Balance at end of year	$	—

Results of Operations for Oil and Gas Producing Activities, Excluding General and Administrative Cost

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

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Company:
Revenue:
Oil and gas revenues	$	2,144	$	23,079		$	63,880
Expenses:
Production costs		1,688		16,980			29,157
Depletion and amortization		370		16,041			36,624
Exploration		—		2			338
Abandoned and impaired properties		—		151,347			419,851
Dry hole costs		—		—			355
Results of operations of oil and gas producing activities	$	86	$	(161,291	)	$	(422,445	)
Income from operations of properties sold, net	$	—	$	—		$	2,280
Gain on sale of properties		—		—			6,874
Income from results of discontinued operations of oil and gas producing activities	$	—	$	—		$	9,154
Company’s share of Piceance Energy:
Revenue:
Oil and gas revenues	$	6,464
Expenses:
Production costs		3,033
Depletion and amortization		2,808
Exploration		—
Abandoned and impaired properties		—
Dry hole costs		—
Results of operations of oil and gas producing activities	$	623
Total Company and Piceance Energy income from operations of oil and gas producing activities	$	709

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Intangible Assets Estimated Amortization Expense (Detail) (Texadian Energy, Inc., USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Texadian Energy, Inc.
Estimated Amortization Expense [Line Items]
2013	$ 2,008
2014	2,008
2015	908
2016	908
2017	908
Thereafter	2,069
Total	$ 8,809

XML

Investments in Piceance Energy - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Aug. 31, 2012
Schedule of Equity Method Investments [Line Items]
Number of hedging unites	10,000
Derivative floor price	3.18
Derivative floor price	4.22
Average floor price	3.46
Average Price
Schedule of Equity Method Investments [Line Items]
Derivative maturity date	2024-09
Fixed Price | Minimum
Schedule of Equity Method Investments [Line Items]
Derivative expiring date	2017
Fixed Price | Maximum
Schedule of Equity Method Investments [Line Items]
Derivative expiring date	2032
Piceance Energy
Schedule of Equity Method Investments [Line Items]
Equity method investment ownership percentage	33.34%	33.34%
Capital contributions by member	$ 60
Secured revolving credit facility	400.0
Initial borrowing base	140
Increase in equity method investments	$ 15.9

XML

Commitments and Contingencies - Additional Information (Detail) (USD $)	1 Months Ended	4 Months Ended	12 Months Ended	1 Months Ended		3 Months Ended		1 Months Ended		3 Months Ended
	Aug. 31, 2012 LegalMatter	Dec. 31, 2012 LegalMatter	Dec. 31, 2012 LegalMatter	Aug. 31, 2012 U.S. Government Claims LegalMatter	Dec. 31, 2012 U.S. Government Claims LegalMatter	Mar. 19, 2013 Subsequent Event LegalMatter	Mar. 19, 2013 Subsequent Event U.S. Government Claims LegalMatter	Sep. 19, 2012 Wapiti Oil And Gas	Sep. 19, 2012 Wapiti Trust	Mar. 19, 2013 Wapiti Trust Subsequent Event
Commitment And Contingencies [Line Items]
Funding of trust		$ 1,000,000	$ 1,000,000
One-time cash payment as consideration for release of claims								1,500,000
Distribution received from trust									1,000,000	5,200,000
Number of claims filed	106			3
Amount of claims filed	73,736,110			22,364,000
Number of claim settled		25	25			25
Amount of claim settled		6,600,112	6,600,112			12,332,511
Amount of claim settled in cash		258,905	258,905			676,092
Amount of claim settled in share		202,753	202,753			1,469,575
Number of remaining claim to be resolved		81	81		3	56	3
Amount of remaining claim to be resolved		67,135,998	67,135,998		22,364,000	54,803,487	22,364,000
Percentage of working interest						2.41934%
Ratio of allowed claims per $1000		544	544
Amount of remaining claim to be resolved		$ 8,700,000	$ 8,700,000

XML

Debt - Additional Information (Detail) (USD $)	4 Months Ended	12 Months Ended			8 Months Ended	12 Months Ended		1 Months Ended			1 Months Ended		12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2012 7% Senior Unsecured Notes, due 2015	Dec. 31, 2012 3 3/4% Senior Convertible Notes, due 2037	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor	Mar. 15, 2005 Predecessor 7% Senior Unsecured Notes, due 2015	Apr. 25, 2007 Predecessor 3 3/4% Senior Convertible Notes, due 2037	Dec. 27, 2012 Letter of Credit	Dec. 27, 2012 Financial Standby Letter of Credit	Mar. 31, 2012 Debtor in Possession Credit Agreement Predecessor	Dec. 31, 2011 Debtor in Possession Credit Agreement Predecessor	Dec. 31, 2012 Debtor in Possession Credit Agreement Predecessor	Dec. 31, 2012 Series of Forbearance Agreements Predecessor	Dec. 31, 2012 Senior Secured Delayed Draw Term Loan	Dec. 31, 2012 Senior Secured Delayed Draw Term Loan Tranche B Term Loan	Dec. 31, 2012 Senior Secured Delayed Draw Term Loan Minimum
Debt Disclosure [Line Items]
Increase in borrowing capacity											$ 1,400,000				$ 30,000,000
Borrowed term loan															13,465,000
Interest rate under credit facility													13.00%			9.75%
Repayment premium																	3.00%
Interest rate after an event of default															11.75%	11.75%
Percentage of repayment of principal amount															100.00%
Percentage of prepayment premium															6.00%
Fair value of embedded derivatives	65,000	65,000													65,000
Term loan facility																35,000,000
Debt instrument principal prepayment amount																100,000
Term loan facility, maturity date																Jul. 01, 2013
Exit fee																5.00%
Line credit maximum borrowing amount									30,000,000		58,900,000	57,500,000
Cash pledged as percentage of undrawn amount of all outstanding letters of credit									105.00%
Letter of credit fee									1.50%
Line credit maturity date									Dec. 26, 2013
Letter of credit issued										11,710,000
Warrants to purchase shares of common stock	9,592,125	9,592,125
Common stock warrant exercise price	0.01	0.01
Common stock warrant expiration period	Aug. 31, 2022	Aug. 31, 2022
Exercise price of warrants multiplier fraction, numerator		147,655,815
Fair value of warrant on grant date		6,600,000
Interest expense on debt	1,056,000				6,852,000	32,324,000
Interest accrued in kind	432,000
Accretion of interest expense	33,000					2,126,000
Percentage of premium on repayment of debt	592,000
Percentage of premium on repayment of debt	3.00%
Repayment of amount outstanding												45,000,000
Additional interest rate under credit facility													6.00%
Initial maturity date of credit facility													2012-06-30	2012-08-31
Interest percentage of senior notes			7.00%	3.75%			7.00%	3.75%
Maturity period			2015	2037			2015	2037
Aggregate principal amount of senior unsecured notes						150,000,000	150,000,000
Aggregate principal amount of senior unsecured notes						115,000,000		115,000,000
Net proceeds from issuance of convertible notes								111,600,000
Discounts and commissions of convertible notes								$ 3,400,000

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Income Taxes - Additional Information (Detail) (USD $)	4 Months Ended		4 Months Ended		8 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Minimum	Dec. 31, 2012 Maximum	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor
Income Taxes [Line Items]
Reduction in operating loss	$ (230,000,000)
U.S. Federal income tax rate	35.00%				(35.00%)	(35.00%)
Non-cash income tax benefit related to gains from discontinued oil and gas operations						5,000,000
Net operating loss carryovers	1,286,000,000
Net operating loss carryforwards expiration year			2027	2032
Capital Loss carryovers	74,700,000
Capital Loss carryovers, expiry year			2015	2016
Alternative minimum tax credit carryovers	$ 785,000	$ 1,045,000

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Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2012 Customer	Aug. 31, 2012 Customer	Dec. 31, 2012 Customer	Dec. 31, 2011 Customer
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Asset retirement obligations settled			$ 3,900,000
Long term debt fair value	10,900,000		10,900,000
Estimated current yield of long term debt	15.40%		15.40%
Accrued settlement claims	8,700,000		8,700,000
Number of major customers			2	3
Entity wide revenue, major customer percentage	96.00%		54.00%	59.00%
Number of major customers	1	2		2
Minimum
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives			3 years
Maximum
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives			15 years
Customer 1
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Entity wide revenue, major customer percentage		59.00%		56.00%
Customer 2
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Entity wide revenue, major customer percentage		24.00%		19.00%
Letter of Credit
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Restricted cash	19,000,000		19,000,000
Bankruptcy Settlement
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Restricted cash	5,000,000		5,000,000
Predecessor
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Restricted cash				0
Impairment of asset held for sale		151,300,000
Assets impairment charges		151,300,000		420,400,000
Predecessor | DHS Drilling Company
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Ownership rate	49.80%		49.80%

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Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2012

Summary of Oil and Gas Segment and Drilling Segment Revenues and Expenses Included in Discontinued Operations

The following table shows the oil and gas segment and drilling segment revenues and expenses included in discontinued operations as described above ended December 31, 2011 (in thousands):

	Predecessor Year Ended December 31, 2011
	Oil and Gas			Drilling			Total
Revenues:
Oil and gas sales	$	10,276		$	—		$	10,276
Contract drilling and trucking fees		—			45,241			45,241
Total Revenues		10,276			45,241			55,517
Operating Expenses:
Lease operating expense		2,482			—			2,482
Transportation expense		16			—			16
Production taxes		370			—			370
Dry hole costs and impairments(1)		608			—			608
Depreciation, depletion, amortization and accretion – oil and gas		2,796			—			2,796
Drilling and trucking operating expenses		—			35,617			35,617
Depreciation and amortization – drilling and trucking(2)		—			2,669			2,669
General and administrative expense		—			3,014			3,014
Total operating expenses		6,272			41,300			47,572
Operating income		4,004			3,941			7,945
Other income and (expense):
Interest expense and financing costs, net		—			(6,911	)		(6,911	)
Other income		—			2,734			2,734
Total other expense		—			(4,177	)		(4,177	)
Income (loss) from discontinued operations		4,004			(236	)		3,768
Income tax expense(3)		(1,724	)		—			(1,724	)
Income (loss) from results of operations of discontinued operations, net of tax		2,280			(236	)		2,044
Gain on sales of discontinued operations, net of tax(4)		6,874			5,176			12,050
Income from results of operations and sale of discontinued operations, net of tax	$	9,154		$	4,940		$	14,094

⁽¹⁾ Dry Hole Costs and Impairments. In 2011, we recorded impairments on our Columbia River, Greentown and Gulf Coast properties of $491,000 prior to their sale. In accordance with accounting standards, the impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction with the Wapiti Transaction were reflected as discontinued operations.

⁽²⁾ Depreciation and Amortization – Drilling and Trucking. Depreciation and amortization– drilling and trucking was $2.7 million for the year ended December 31, 2011. We stopped recording depreciation expense beginning in March 2011 in accordance with accounting rules related to the asset held for sale treatment of DHS.

⁽³⁾ Income tax expense. For the year ended December 31, 2011, we recorded a tax benefit of approximately $1.2 million due to a non-cash income tax benefit related to gains from discontinued oil and gas operations. U.S. GAAP requires all items be considered, including items recorded in discontinued operations, in determining the amount of tax benefit that results from a loss from continuing operations that should be allocated to continuing operations. In accordance with U.S. GAAP, we recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations.

⁽⁴⁾ Gain on sales of discontinued operations – oil and gas. In accordance with U.S. GAAP, we recognized a $5.6 million gain on sale ($8.9 million gain, net of $3.3 million of tax) for the year ended December 31, 2011 that is reflected in discontinued operations. In June 2011, DHS sold certain of its trucking assets for $3.3 million in proceeds and a gain of $2.9 million.

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Income Tax Expense (Benefit) Attributable To Income from Continuing Operations (Detail) (USD $) In Thousands, unless otherwise specified	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor
Current:
U.S.-Federal		$ 0
U.S.-State		0
Foreign		0
Deferred:
U.S.-Federal	(2,757)	0	(4,329)
U.S.-State		0
Total	$ (2,757)	$ 0	$ (4,329)

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Future Minimum Payments under Operating Leases That Have Remaining Term in Excess of One Year (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Operating Leased Assets [Line Items]
2013	$ 1,496
2014	1,496
2015	1,496
2016	1,496
2017	660
Operating Leases, Future Minimum Payments Due, Total	$ 6,644

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Capitalized Costs Related to Oil and Gas Activities (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012 Successor	Dec. 31, 2012 Successor Company	Dec. 31, 2012 Successor Company's Share of Piceance Energy	Dec. 31, 2011 Predecessor	Aug. 31, 2012 Predecessor Company		Dec. 31, 2011 Predecessor Company
Oil and Gas In Process Activities [Line Items]
Unproved properties	$ 0		$ 16,180	$ 72,081	$ 84	[1]	$ 72,081
Proved properties	4,804	4,804	134,638	688,521	759,755	[1]	688,521
Oil and Gas Property, Successful Effort Method, Gross, Total		4,804	150,818		759,839	[1]	760,602
Accumulated depreciation and depletion		(337)	(2,808)		(642,172)	[1]	(442,169)
Oil and gas property, successful efforts method		$ 4,467	$ 148,010		$ 117,667	[1]	$ 318,433

[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 accounting (see Note 2).

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Long Term Debt (Detail) (USD $)	Dec. 31, 2012
Debt Instrument [Line Items]
Total debt, net of unamortized debt discount	$ 42,391,000
Less: current maturities	(35,000,000)
Long term debt, net of current maturities and unamortized discount	7,391,000
Senior Secured Delayed Draw Term Loan
Debt Instrument [Line Items]
Delayed Draw Term Loan Agreement	13,465,000
Senior Secured Delayed Draw Term Loan | Tranche B Term Loan
Debt Instrument [Line Items]
Tranche B Loan	35,000,000
Warrant
Debt Instrument [Line Items]
Less: unamortized debt discount	(6,014,000)
Embedded Derivative
Debt Instrument [Line Items]
Less: unamortized debt discount	$ (60,000)

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Summary of Stock Option Activity under Predecessor's Various Plans and Related Information (Detail) (USD $)	8 Months Ended	12 Months Ended
	Aug. 31, 2012	Dec. 31, 2011
Options
Outstanding-beginning of year	150,300	160,800
Granted
Exercised
Expired / canceled	(150,300)	(10,500)
Outstanding-end of year	0	150,300
Exercisable-end of year	0	150,300
Weighted-Average Exercise Price
Outstanding-beginning of year	$ 75.00	$ 72.60
Granted
Exercised
Expired / canceled	$ (75.00)	$ (38.96)
Outstanding-end of year	$ 0	$ 75.00
Exercisable-end of year	$ 0	$ 75.00
Weighted-Average Remaining Contractual Term
Outstanding-end of year	0 years	2 years 7 months 21 days
Exercisable-end of year	0 years	2 years 7 months 21 days
Aggregate Intrinsic Value
Outstanding-end of year	$ 0
Exercisable-end of year	$ 0

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Segment Information - Additional Information (Detail) (USD $)	4 Months Ended
	Dec. 31, 2012 Segment
Number of businsess segment	2
Natural Gas and Oil Exploration and Production
Expenditures for long term assets, including goodwill and other intangible assets	415,000
Commodity Transportation and Marketing
Expenditures for long term assets, including goodwill and other intangible assets	17,400,000

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Components of Deferred Tax Assets (Liabilities) (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Deferred tax assets:
Net operating loss	$ 450,195	$ 450,632
Capital loss carry forwards	26,141	35,919
Asset retirement obligation	179	1,398
Property and equipment	23,045	39,912
Investment in Piceance Energy	45,172
Equity compensation		10,448
Equity investments		329
Derivative instruments	1,498
Minimum tax credit	785	1,045
Contribution carryforwards	189	517
Accrued bonuses		517
Allowance for doubtful accounts		93
Accrued vacation		125
Texadian Energy	326
Other	27	69
Total deferred tax assets	547,557	541,004
Valuation allowance	(544,442)	(540,724)
Net deferred tax assets	3,115	280
Deferred tax liabilities:
Property and equipment
Texadian Energy intangibles	3,083
Prepaid insurance, marketable securities and other	32	280
Total deferred tax liabilities	3,115	280
Total deferred taxes, net	$ 0	$ 0

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Financial Information for Reportable Segments (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Segment Reporting Information [Line Items]
Current assets	$ 49,132
Net property and equipment	5,846
Investments in unconsolidated affiliates	104,434
Goodwill and other intangible assets	16,565
Assets held for sale	2,800
Other long term assets	11
Totals	178,788
Natural Gas and Oil Exploration and Production
Segment Reporting Information [Line Items]
Current assets	2,951
Net property and equipment	5,846
Investments in unconsolidated affiliates	104,434
Assets held for sale	2,800
Other long term assets	3
Totals	116,034
Commodity Transportation and Marketing
Segment Reporting Information [Line Items]
Current assets	46,181
Goodwill and other intangible assets	16,565
Assets held for sale	0
Other long term assets	8
Totals	$ 62,754

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Summary of Restricted Stock (Nonvested Stock) Activity under Predecessor's Plan and Related Information (Detail) (USD $)	8 Months Ended	12 Months Ended
	Aug. 31, 2012	Dec. 31, 2011
Nonvested Stock
Non vested balance, beginning of period	558,301	734,376
Granted	0	598,836
Vested	0	(719,350)
Expired / canceled	(558,301)	(55,561)
Non vested balance, end of period	0	558,301
Weighted-Average Grant-Date Fair Value
Non vested balance, beginning of period	$ 7.45	$ 15.27
Granted	$ 0	$ 5.92
Vested	$ 0	$ (11.74)
Expired / canceled	$ (7.45)	$ (36.22)
Non vested balance, end of period	$ 0	$ 7.45
Weighted-Average Remaining Contractual Term
Nonvested-end of year	0 years	5 months 23 days
Aggregate Intrinsic Value
Nonvested-end of year	$ 0	$ 3,307

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Summary of Claims (Detail) (USD $)	1 Months Ended	4 Months Ended	12 Months Ended	3 Months Ended	1 Months Ended			1 Months Ended	12 Months Ended	3 Months Ended	1 Months Ended			1 Months Ended			1 Months Ended		12 Months Ended		3 Months Ended
	Aug. 31, 2012 LegalMatter	Dec. 31, 2012 LegalMatter	Dec. 31, 2012 LegalMatter	Mar. 19, 2013 Subsequent Event LegalMatter	Aug. 31, 2012 U.S. Government Claims LegalMatter	Dec. 31, 2012 U.S. Government Claims LegalMatter	Mar. 19, 2013 U.S. Government Claims Subsequent Event LegalMatter	Aug. 31, 2012 Former Employee Claims LegalMatter	Dec. 31, 2012 Former Employee Claims LegalMatter	Mar. 19, 2013 Former Employee Claims Subsequent Event LegalMatter	Aug. 31, 2012 Macquarie Capital (USA) Inc. LegalMatter	Dec. 31, 2012 Macquarie Capital (USA) Inc. LegalMatter	Mar. 19, 2013 Macquarie Capital (USA) Inc. Subsequent Event LegalMatter	Aug. 31, 2012 Swann and Buzzard Creek Royalty Trust LegalMatter	Dec. 31, 2012 Swann and Buzzard Creek Royalty Trust LegalMatter	Mar. 19, 2013 Swann and Buzzard Creek Royalty Trust Subsequent Event LegalMatter	Aug. 31, 2012 Other Various Claims LegalMatter		Dec. 31, 2012 Other Various Claims LegalMatter		Mar. 19, 2013 Other Various Claims Subsequent Event LegalMatter
Commitments and Contingencies [Line Items]
Filed Claims Count	106				3			32			1			1			69	[1]
Filed Claims Amount	$ 73,736,110				$ 22,364,000			$ 16,379,849			$ 8,671,865			$ 3,200,000			$ 23,120,396	[1]
Settled Claims Count		25	25	25					13	12									12	[1]	13	[1]
Settled Claims Amount		6,600,112	6,600,112	12,332,511					3,685,253	11,750,904									2,914,859	[1]	581,607	[1]
Settled Claims Consideration, Cash		258,905	258,905	676,092					229,478	278,338									29,427	[1]	397,754	[1]
Settled Claims Consideration, Stock		202,753	202,753	1,469,575					202,231	1,361,452									522	[1]	108,123	[1]
Remaining Filed Claims Count		81	81	56		3	3		19	7		1	1		1	1			57	[1]	44	[1]
Remaining Filed Claims Amount		$ 67,135,998	$ 67,135,998	$ 54,803,487		$ 22,364,000	$ 22,364,000		$ 12,694,596	$ 943,692		$ 8,671,865	$ 8,671,865		$ 3,200,000	$ 3,200,000			$ 20,205,537	[1]	$ 19,623,930	[1]

[1] Includes reserve for contingent/unliquidated claims in the amount of $10 million

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Subsequent Events

12 Months Ended

Dec. 31, 2012

Subsequent Events

(19) Subsequent Events

On January 17, 2013, we drew an additional $8.0 million on our Loan Agreement to support Texadian’s working capital requirements. On February 20, 2013, we sold our compressors that were classified for sale for $2.8 million. Through March 25, 2013, we have issued 1,469,575 shares of our common stock to settle various bankruptcy claims.

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Balance Sheet for Piceance Energy (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Assets
Total property and equipment, net	$ 5,846
Total assets	189,582
Piceance Energy
Assets
Cash and equivalents	234
Accounts receivable	4,836
Prepaids and other assets	1,205
Total current assets	6,275
Oil and gas property, successful efforts method	533,279
Property, plant and equipment, gross	549,687
Less: accumulated depletion, depreciation and amortization	(89,673)
Total property and equipment, net	460,014
Deferred issue costs and other assets, net	977
Total assets	467,266
Liabilities and Members' Equity
Account s payable and accrued liabilities	10,169
Oil and gas sales payable	1,657
Total current liabilities	11,826
Note payable	90,000
Derivative liabilities	1,525
Asset retirement obligation	2,844
Total non-current liabilities	94,369
Total liabilities	106,195
Members equity
Members' equity	365,046
Accumulated deficit	(3,975)
Total members equity	361,071
Total liabilities and members' equity	467,266
Piceance Energy | Other Real Estate Owned Assets Land
Assets
Property, plant and equipment, gross	14,322
Piceance Energy | Furniture and Fixtures
Assets
Property, plant and equipment, gross	2,086
Piceance Energy | Equity Method Investments, Our Share
Assets
Cash and equivalents	78
Accounts receivable	1,612
Prepaids and other assets	402
Total current assets	2,092
Oil and gas property, successful efforts method	177,795
Property, plant and equipment, gross	183,265
Less: accumulated depletion, depreciation and amortization	(29,897)
Total property and equipment, net	153,368
Deferred issue costs and other assets, net	325
Total assets	155,785
Liabilities and Members' Equity
Account s payable and accrued liabilities	3,390
Oil and gas sales payable	552
Total current liabilities	3,942
Note payable	30,006
Derivative liabilities	508
Asset retirement obligation	948
Total non-current liabilities	31,462
Total liabilities	35,404
Members equity
Members' equity	121,706
Accumulated deficit	(1,325)
Total members equity	120,381
Total liabilities and members' equity	155,785
Piceance Energy | Equity Method Investments, Our Share | Other Real Estate Owned Assets Land
Assets
Property, plant and equipment, gross	4,775
Piceance Energy | Equity Method Investments, Our Share | Furniture and Fixtures
Assets
Property, plant and equipment, gross	$ 695

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Reorganization under Chapter 11 - Additional Information (Detail) (USD $)									1 Months Ended
	Dec. 31, 2012	Aug. 31, 2012 Laramie	Dec. 31, 2012 Reorganized Delta Petroleum Person	Aug. 31, 2012 Reorganized Delta Petroleum	Jun. 04, 2012 Reorganized Delta Petroleum	Dec. 31, 2012 Piceance Energy	Aug. 31, 2012 Piceance Energy	Jun. 04, 2012 Piceance Energy	Dec. 31, 2012 Piceance Energy Laramie	Jun. 04, 2012 Piceance Energy Laramie	Jun. 04, 2012 Piceance Energy Reorganized Delta Petroleum
Reorganization [Line Items]
Ownership interest held in Piceance Energy, percentage		66.66%		33.34%		33.34%	33.34%			66.66%	33.34%
Amount distributed to pay bankruptcy expenses and secured debt										$ 24,900,000	$ 72,600,000
Amount borrowed under new credit agreement				13,000,000	13,000,000			100,000,000
Significant shareholder ownership percentage			5.00%
Number of board of directors			5
Common stock shares issued	147,700,000
Monthly management services fee									$ 650,000

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Incentive Plan Activity (Detail) (USD $)	8 Months Ended	12 Months Ended	4 Months Ended
	Aug. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Long Term Incentive Plan
Stock Awards, Shares
Non vested balance, beginning of period	558,301	734,376
Granted	0	598,836	2,191,834
Vested	0	719,350
Forfeited	558,301	55,561
Non vested balance, end of period	0	558,301	2,191,834
Stock Awards, Weighted-Average Grant Date Fair Value
Non vested balance, beginning of period	$ 7.45	$ 15.27
Granted	$ 0	$ 5.92	$ 1.09
Vested	$ 0	$ 11.74
Forfeited	$ 7.45	$ 36.22
Non vested balance, end of period	$ 0	$ 7.45	$ 1.09

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Principal Sources of Changes in Standardized Measure of Discounted Net Cash Flows (Detail) (USD $) In Thousands, unless otherwise specified				4 Months Ended			8 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 Company	Dec. 31, 2012 Company's Share of Piceance Energy	Dec. 31, 2012 Successor	Dec. 31, 2012 Successor Company	Dec. 31, 2012 Successor Company's Share of Piceance Energy	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Beginning of the period	$ 79,969	$ 8,010	$ 71,959	$ 7,223	$ 7,223		$ 129,695	$ 192,094
Transfer from investees				55,253		55,253
Sales of oil and gas production during the period, net of production costs				(4,095)	(456)	(3,639)	(5,954)	(42,187)
Purchase of reserves in place
Net change in prices and production costs				(806)	(667)	(139)	378	7,906
Changes in estimated future development costs				5		5		8,319
Extensions, discoveries and improved recovery				1,332	763	569
Revisions of previous quantity estimates, estimated timing of development and other				14,356	648	13,708	(7,439)	(17,130)
Previously estimated development and abandonment costs incurred during the period								2,453
Sales/disposition of reserves in place							(118,104)	(40,969)
Change in future income tax
Other				4,618	258	4,360
Accretion of discount				2,083	241	1,842	8,647	19,209
End of period	$ 79,969	$ 8,010	$ 71,959	$ 79,969	$ 8,010	$ 71,959	$ 7,223	$ 129,695

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2012

Computation of Basic and Diluted Earnings Per Share

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

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Net loss attributable to common stockholders	$	(8,839	)	$	(45,437	)	$	(484,134	)
Gain from discontinued operations, net of tax		0			—			14,023
Net loss attributable to common stockholders	$	(8,839	)	$	(45,437	)	$	(470,111	)
Basic weighted-average common stock outstanding		157,335			28,841			28,841
Add: dilutive effects of stock options and unvested stock grants		0			—			—
Diluted weighted-average common stock outstanding		157,335			28,841			28,841
Basic loss per common share attributable to common stockholders:
Loss from continuing operations	$	(0.06	)	$	(1.57	)	$	(16.79	)
Discontinued operations		0			—			0.49
Net loss	$	(0.06	)	$	(1.57	)	$	(16.30	)
Diluted loss per common share attributable to common stockholders:
Loss from continuing operations	$	(0.06	)	$	(1.57	)	$	(16.79	)
Discontinued operations		0			—			0.49
Net loss	$	(0.06	)	$	(1.57	)	$	(16.30	)

Potentially Dilutive Securities Excluded from Calculation of Diluted Shares Outstanding

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

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012		Year Ended December 31, 2011
Stock issuable upon conversion of convertible notes		0		379		379
Stock options		0		150		150
Non-vested restricted stock		0		558		558
Total potentially dilutive securities		0		1,087		1,087

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Acquisition - Additional Information (Detail) (Texadian Energy, Inc., USD $)	4 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011
Texadian Energy, Inc.
Business Acquisition [Line Items]
Business acquisition, cash consideration	$ 14,000,000	$ 14,000,000
Business acquisition purchase price allocation working capital	4,000,000	4,000,000
Bussiness acquisition cash paid at closing	18,000,000	18,000,000
Weighted average useful life		7 years 3 months 18 days
Oil and gas sales	122,900,000	515,500,000	731,000,000
Net income (loss)	800,000	2,300,000	(748,000)
Oil and gas sales, had the acquisition occurred as of September 1, 2012		125,000,000
Net income (loss), had the acquisition occurred as of September 1, 2012		8,600,000
Acquisition costs		$ 556,000

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Discontinued Operations - Additional Information (Detail) (Predecessor, USD $)	3 Months Ended	8 Months Ended	12 Months Ended	1 Months Ended
	Jun. 30, 2011	Aug. 31, 2012	Dec. 31, 2011	Oct. 31, 2011 DHS Drilling Company
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gross cash proceeds from sale of interests in non core assets	$ 43,200,000
Ownership interest sold by the company				49.80%
Sale proceeds for ownership interests sold		$ 0	$ 1,517,000	$ 500,000

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Fair Value Measurements - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012
Fair Value Measurements [Line Items]
Stock price	$ 0.70
Fair value assumption, exercise price	$ 0.01
Fair value assumption, expected term	10 years
Fair value assumption, risk free interest rate	1.70%
Fair value assumption, expected volatility	75.00%
Fair value assumption, historical volatilities period	10 years
Fair value of warrants issued	$ 6,600,000
Fair value of warrants per share	$ 0.69
Fair value of embedded derivatives	$ 65,000

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Reconciliation of Asset Retirement Obligations (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended	4 Months Ended	8 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 Successor	Aug. 31, 2012 Predecessor
Asset Retirement Obligations [Line Items]
Asset retirement obligation - beginning of period	$ 3,931	$ 476	$ 3,799
Accretion expense	273	36	178
Change in estimate	(135)	0	437
Obligations incurred (from new wells)	385	0
Obligations settled	(296)	0
Obligations on sold properties	(359)	0
Settlement upon transfer to Piceance Energy			(3,938)
Asset retirement obligation - end of period	3,799	512	476
Less: Current portion of asset retirement obligation	(292)	0
Long-term asset retirement obligation	$ 3,507	$ 512	$ 476

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Summary of Significant Accounting Policies

(3) 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. Certain of our oil and gas activities may be conducted through partnerships and joint ventures. We will include our proportionate share of assets, liabilities, revenues and expenses from these entities in our consolidated financial statements. 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 Par Piceance Energy, LLC, which owns our investment in Piceance Energy (see Note 4), and Texadian Energy, Inc. (formerly known as SEACOR Energy Inc. (“Texadian”)), which we acquired December 31, 2012 (see Note 5).

Accounting for the Chapter 11 Filing

The Predecessor followed the accounting prescribed by ASC 852. This accounting literature provides guidance for periods subsequent to a Chapter 11 filing regarding the presentation of liabilities that are and are not subject to compromise by the bankruptcy court proceedings, as well as the treatment of interest expense and presentation of costs associated with the proceedings. As a result of the reorganization, the realization of assets and the satisfaction of liabilities were subject to uncertainty. While operating as a debtor-in-possession under Chapter 11, Predecessor’s ability to sell or otherwise dispose of or liquidate assets or settle liabilities, were subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Credit Facility), in amounts other than those reflected in the accompanying consolidated financial statements of the Predecessor. The accompanying Predecessor consolidated financial statements for the year ended December 31, 2011 do not include any direct adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary as a consequence of the reorganization under the Plan.

The Reorganizations Topic of ASC 852, which is applicable to companies in Chapter 11, generally does not change the manner in which financial statements are prepared. However, it does require that the financial statements for periods subsequent to the filing of the Plan distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Amounts that can be directly associated with the reorganization and restructuring of the business must be reported separately as reorganization items in the statements of operations beginning in the quarter ending December 31, 2011. The balance sheet must distinguish pre-petition liabilities subject to compromise from both those pre-petition liabilities that are not subject to compromise and from post-petition liabilities. Liabilities that may be affected by a plan of reorganization must be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. In addition, cash provided by and used for reorganization items must be disclosed separately. The Company has applied the Reorganizations Topic of ASC 852 effective as of the Effective Date, and has segregated those items as outlined above for all reporting periods subsequent to such date.

Cash Equivalents

We consider all highly liquid investments with maturities at date of acquisition of three months or less to be cash equivalents.

Restricted Cash

As of December 31, 2012, restricted cash consists of amounts held at a commercial bank to support our letter of credit facility totaling approximately $19.0 million (see Note 6). In addition, we have restricted cash of approximately $5.0 million designated to settle bankruptcy matters that is not available for operating activities (see Note 9).

Trade Receivables

As of December 31, 2012, Texadian’s customers primarily included major independent refining and marketing companies. Customers are required to pay in advance or are granted credit on a short-term basis when credit risks are considered minimal. We routinely review our trade receivables and make provisions for doubtful accounts based on existing customer and economic conditions; however, those provisions are estimates and actual results could differ from those estimates and those differences may be material. Trade receivables are deemed uncollectible and removed from accounts receivable and the allowance for doubtful accounts when collection efforts have been exhausted. As of December 31, 2012, we had no allowance for doubtful accounts. Additionally, we provide an accrual for oil and natural gas sales using the sales method by estimating oil and natural gas volumes and prices for months in which revenues have not been received using production and pricing information provided by the operator. Most of Texadian’s physical purchases and sales with the same counterparty are settled on a net basis and therefore Texadian’s receivables are recorded net of any corresponding payables.

Inventories

As of December 31, 2012, Texadian’s inventories, which consist of in transit crude oil, are stated at the lower of cost (using the first-in, first-out method) or market. We record impairments, as needed, to adjust the carrying amount of inventories to the lower of cost or market.

Investments in Unconsolidated Affiliates

Investments in operating entities where we have the ability to exert significant influence, but do not control the operating and financial policies, are accounted for using the equity method. Our share of net income of these entities is recorded as income (loss) from unconsolidated affiliates in the consolidated statements of operations.

At December 31, 2012, our investment in unconsolidated affiliates consisted of our ownership interest in Piceance Energy (see Note 4). Until November 2011, the Predecessor owned a 49.8% interest in DHS Drilling Company (“DHS”). The Predecessor’s representatives constituted a majority of the members of the board of directors of DHS and the Predecessor had the right to use all of the rigs owned by DHS on a priority basis and, accordingly, DHS was consolidated in these financial statements until we disposed of DHS in 2011.

Assets Held for Sale

As of December 31, 2012, we have classified our compressors as held for sale, which are recorded at the lower of cost or estimated net realizable value. These compressors are not in use and are not being depreciated.

Property and Equipment

We account for our oil and natural gas 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. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological or geophysical expenses and delay rentals for 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, and development costs is computed using the units-of-production method by individual fields (common reservoirs) using proved producing oil and natural gas reserves amortized as the related reserves are produced. Associated leasehold costs are depleted using the unit of production method based on total proved oil and natural gas reserves amortized as the related reserves are produced.

Other property and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives ranging from three to 15 years.

Goodwill and Other Intangible Assets

We recorded goodwill as a result of our acquisition of Texadian. Goodwill is attributable to the synergies 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, as a result of our acquisition of Texadian, 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.

Impairment of Goodwill and Long-Lived Assets

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. Qualitative factors assessed for the reporting unit would include the competitive environments and financial performance of the reporting unit. 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, based upon a multiple of estimated earnings. 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. The fair value calculation uses level 3 (see Note 7) inputs and includes multiple assumptions and estimates, including the projected cash flows and discount rates applied. Changes in these assumptions and estimates could result in goodwill impairment that could materially adversely impact our financial position or results of operations.

Long-lived assets are reviewed for impairment quarterly or when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

Estimates of expected future cash flows represent our best estimate based on reasonable and supportable assumptions and projections. For proved properties, if the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized are permanent and may not be restored in the future.

We assess proved properties on an individual field basis for impairment each quarter when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For proved properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs.

For unproved properties, the need for an impairment charge is based on our plans for future development and other activities impacting the life of the property and our ability to recover our investment. When we believe the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. For the period from September 1 through December 31, 2012, there were no impairments recorded by the Successor. 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 to write-down these assets to fair value at that time. The Predecessor’s assets were further adjusted due to the application of fresh start accounting upon the Predecessor’s emergence from Chapter 11. The Predecessor recognized impairment expenses totaling approximately $151.3 million for the period January 1, 2012 through August 31, 2012 and $420.4 million for the year ended December 31, 2011, respectively.

Asset Retirement Obligations

Our asset retirement obligations arise from the plugging and abandonment liabilities for our oil and gas wells. The following is a reconciliation of our asset retirement obligations (in thousands):

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January  1 through August 31, 2012			Year Ended December 31, 2011
Asset retirement obligation – beginning of period	$	476	$	3,799		$	3,931
Accretion expense		36		178			273
Change in estimate		0		437			(135	)
Obligations incurred (from new wells)		0		—			385
Obligations settled		0		—			(296	)
Obligations on sold properties		0		—			(359	)
Settlement upon transfer to Piceance Energy		—		(3,938	)		—
Asset retirement obligation – end of period		512		476			3,799
Less: Current portion of asset retirement obligation		0		—			(292	)
Long-term asset retirement obligation	$	512	$	476		$	3,507

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

Derivatives and Other Financial instruments

We may periodically enter into commodity price risk transactions to manage our exposure to ethanol, oil and gas 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.

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, we issued warrants (see Note 6) that are not considered to be indexed to our equity. Accordingly, these warrants are accounted for as liabilities. In addition, the Loan Agreement contains certain puts that are 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.

The carrying value of trade accounts receivable and accounts payable approximates fair value due to their short term nature. Our long-term debt is recorded on the amortized cost basis. We estimate its fair value to be approximately $10.9 million at December 31, 2012 using a discounted cash flow analysis and an estimate of the current yield (15.4%) by reference to market interest rates for term debt of comparable companies which is considered a level 3 fair value measurement (see Note 7). Our derivatives are recorded at fair value.

Accrued Settlement Claims

As of December 31, 2012, we have accrued approximately $8.7 million relating to claims resulting from our bankruptcy (See Note 9).

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 based on a “more likely than not” standard, and to the extent this threshold is not met, a valuation allowance is recorded.

We recognize in the financial statements 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 2009, 2010, and 2011. 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.

Stock Based Compensation

We recognize the cost of share based payments over the period the employee provides service, generally the vesting period, and includes such costs in general and administrative expense in the 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

Oil and Gas

Revenues are recognized when title to the products transfers to the purchaser. We follow the “sales method” of accounting for our natural gas and crude oil revenue, so that we recognize sales revenue on all natural gas or crude oil sold to its 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, 2012, our aggregate natural gas and crude oil imbalances were not material to our consolidated financial statements.

Marketing and Transportation

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.

Texadian will earn revenues from the sale of crude oil, blendstocks and refined products, the rental of rail cars, and through voyage affreightment contracts on leased-in liquid tank barges and towboats. Revenues and related costs from crude oil, blendstocks and refined products are recorded when title transfers to the buyer. Revenues from the rental of railcars are recognized ratably over the lease periods. Revenues from voyage affreightment contracts are generally recognized over the progress of the voyage while the related costs are expensed as incurred. Unearned revenues arise and are recorded as a liability when customers pay in advance for products or services.

Major Customers

For the year ended December 31, 2012 and 2011, two and three customers accounted for approximately 54% and 59%, respectively, of Texadian’s operating revenues (see Note 5). The loss of any of these customers could have a material adverse effect on our future results of operations.

For the period September 1, 2012 to December 31, 2012, we had one customer that accounted for 96% of the Sucessor’s total oil and natural gas sales. During the period from January 1, 2012 to August 31, 2012 we had two customer that accounted individually for 59% and 24%, respectively, of the Predecessor’s total oil and natural gas sales. For the year ended December 31, 2011, two customers accounted individually for 56% and 19%, respectively, of the Predecessor’s total oil and gas sales. Although a substantial portion of production is purchased by these major customers, we do not believe that the loss of a customer would have a material adverse effect on our business as other customers or markets would be accessible to us.

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 foreign currency losses, net in the accompanying consolidated statements of operations in the period in which the currency exchange rates change.

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 under fresh start accounting, fair value of assets and liabilities recorded under purchase accounting, oil and natural gas reserves, bad debts, depletion and impairment of oil and natural gas properties, income taxes and the valuation allowances related to deferred tax assets, derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.

Recently Adopted Guidance

Comprehensive Income—In June 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-05, related to ASC Topic 220, Comprehensive Income: Presentation of Comprehensive Income and in December 2011 the FASB issued ASU 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU 2011-05. These standards eliminate the current option to report other comprehensive income and its components in the statement of changes in equity. The adoption of this amendment in 2012 did not have a material effect on the presentation of our consolidated financial statements.

Fair Value Measurement—In May 2011, the FASB issued new guidance related to ASC Topic 820, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The new guidance results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and International Financial Reporting Standards (“IFRS”), changes some fair value measurement principles and requires additional disclosure. The ASU was effective for interim and annual periods beginning on or after December 15, 2011. The adoption of this amendment in 2012 did not have a material effect on the presentation of our consolidated financial statements.

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Assets and Liabilities Measured At Fair Value on Recurring Basis (Detail) (Fair Value, Measurements, Recurring, USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Liabilities Derivatives:
Liabilities derivatives, fair value	$ (11,252)
Commodity Contract | Exchange Traded Futures
Assets Derivatives:
Commodities - exchange traded futures	542
Commodity Contract | Physical Forward Contracts
Liabilities Derivatives:
Liabilities derivatives, fair value	(307)
Warrant
Liabilities Derivatives:
Liabilities derivatives, fair value	(10,900)
Embedded Derivative Financial Instruments
Liabilities Derivatives:
Liabilities derivatives, fair value	(45)
Fair Value, Inputs, Level 1 | Commodity Contract | Exchange Traded Futures
Assets Derivatives:
Commodities - exchange traded futures	542
Fair Value, Inputs, Level 2
Liabilities Derivatives:
Liabilities derivatives, fair value	(307)
Fair Value, Inputs, Level 2 | Commodity Contract | Physical Forward Contracts
Liabilities Derivatives:
Liabilities derivatives, fair value	(307)
Fair Value, Inputs, Level 3
Liabilities Derivatives:
Liabilities derivatives, fair value	(10,945)
Fair Value, Inputs, Level 3 | Warrant
Liabilities Derivatives:
Liabilities derivatives, fair value	(10,900)
Fair Value, Inputs, Level 3 | Embedded Derivative Financial Instruments
Liabilities Derivatives:
Liabilities derivatives, fair value	$ (45)

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Fresh Start Accounting and Effects of Plan - Additional Information (Detail) (Piceance Energy, USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Aug. 31, 2012
Piceance Energy
Reorganization [Line Items]
Equity method investment ownership percentage	33.34%	33.34%
Investment in Piceance Energy		$ 105,344

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Investments in Piceance Energy (Tables)

12 Months Ended

Dec. 31, 2012

Change in Our Equity Investment in Piceance Energy

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

	Period from September 1 through December 31, 2012
	(in thousands)
Beginning balance	$	105,344
Loss from unconsolidated affiliates		(1,325	)
Capitalized drilling costs obligation paid		415
Ending balance	$	104,434

Balance Sheet for Piceance Energy

Summarized balance sheet information and our share of the equity investment are as follows:

	December 31, 2012
	100%			Our Share
	(in thousands)
Assets
Cash and equivalents	$	234		$	78
Accounts receivable		4,836			1,612
Prepaids and other assets		1,205			402
Total current assets		6,275			2,092
Oil and gas property, successful efforts method		533,279			177,795
Other real estate and land		14,322			4,775
Office furniture and equipment		2,086			695
Total		549,687			183,265
Less: accumulated depletion, depreciation and amortization		(89,673	)		(29,897	)
Total property and equipment, net		460,014			153,368
Deferred issue costs and other assets, net		977			325
Total assets	$	467,266		$	155,785

	December 31, 2012
	100%			Our Share
	(in thousands)
Liabilities and Members’ Equity
Accounts payable and accrued liabilities	$	10,169		$	3,390
Oil and gas sales payable		1,657			552
Total current liabilities		11,826			3,942
Note payable		90,000			30,006
Derivative liabilities		1,525			508
Asset retirement obligation		2,844			948
Total non-current liabilities		94,369			31,462
Total liabilities		106,195			35,404
Members equity
Members’ equity		365,046			121,706
Accumulated deficit		(3,975	)		(1,325	)
Total members equity		361,071			120,381
Total liabilities and members’ equity	$	467,266		$	155,785

Statement of Operations for Piceance Energy

Summarized income statement information and our share for the period for which our investment was accounted for under the equity method is as follows:

	September 1 through December 31, 2012
	100%			Our Share
	(in thousands)
Oil, natural gas and natural gas liquids revenues	$	19,391		$	6,465
Oil and gas operating expenses		9,100			3,034
Depletion, depreciation and amortization		8,523			2,842
Management fee		3,250			1,084
General and administrative		613			204
Total operating expenses		21,486			7,164
Loss from operations		(2,095	)		(699	)
Other income (expense)
Loss from derivatives		(918	)		(306	)
Interest expense and debt issue costs		(976	)		(325	)
Other income		14			5
Total other expense		(1,880	)		(626	)
Net loss	$	(3,975	)	$	(1,325	)

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Reconciliation of Asset Retirement Obligations

 The following is a reconciliation of our asset retirement obligations (in thousands):

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January  1 through August 31, 2012			Year Ended December 31, 2011
Asset retirement obligation – beginning of period	$	476	$	3,799		$	3,931
Accretion expense		36		178			273
Change in estimate		0		437			(135	)
Obligations incurred (from new wells)		0		—			385
Obligations settled		0		—			(296	)
Obligations on sold properties		0		—			(359	)
Settlement upon transfer to Piceance Energy		—		(3,938	)		—
Asset retirement obligation – end of period		512		476			3,799
Less: Current portion of asset retirement obligation		0		—			(292	)
Long-term asset retirement obligation	$	512	$	476		$	3,507

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Information Regarding Proved Oil and Gas Reserves (Unaudited) - Additional Information (Detail)	Dec. 31, 2012
Oil and Gas In Process Activities [Line Items]
Present value of future income taxes, discount rate	10.00%

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Repayment of Premium Equal to Percentage of Principal Repaid (Detail)	4 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 First Anniversary	Dec. 31, 2012 Second Anniversary	Dec. 31, 2012 After Second Anniversary
Long Term Debt Maturities Repayments Of Principal [Line Items]
Percentage of repayment premium from effective date to anniversary	3.00%	6.00%	5.00%	3.00%

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Fresh Start Condensed Consolidated Balance Sheet (Detail) (USD $)	Aug. 31, 2012
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
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)
Net property and equipment	194,688
Long-term assets:
Investments in unconsolidated affiliates	3,629
Other long-term assets	307
Total long-term assets	3,936
Total assets	210,389
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
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
Liabilities not subject to compromise
Long - term debt	0
Derivative liabilities	0
Asset retirement obligations	4,414
Total liabilities	357,273
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
Current assets:
Trust assets	3,446	[1]
Restricted cash	20,359	[2]
Trade accounts receivable, net	(1,727)	[3]
Oil and gas properties,
Proved	(740,392)	[3]
Land	(4,000)	[3]
Other	(47,493)	[3]
Less accumulated depreciation and depletion	607,603	[3]
Long-term assets:
Investments in unconsolidated affiliates	105,344	[3]
Liabilities not subject to compromise
Debtor in possession financing	(56,535)	[4]
Liabilities subject to compromise
3 3/4% Senior notes	(115,000)	[5]
7% Senior convertible notes	(150,000)	[5]
Liabilities not subject to compromise
Long - term debt	6,335	[4]
Derivative liabilities	6,665	[4]
Asset retirement obligations	(3,938)	[3]
Current assets:
Trade accounts receivable, net	(1,981)	[6]
Prepaid assets	(4,777)	[6]
Prepaid reorganization costs	(1,326)	[6]
Oil and gas properties,
Unproved	(84)	[6]
Proved	(14,776)	[6]
Other	(21,289)	[6]
Less accumulated depreciation and depletion	34,569	[6]
Long-term assets:
Investments in unconsolidated affiliates	(3,629)	[6]
Other long-term assets	(253)	[6]
Equity:
Common stock	(288)	[7]
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
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
Net property and equipment	8,826
Long-term assets:
Investments in unconsolidated affiliates	105,344
Other long-term assets	54
Total long-term assets	105,398
Total assets	142,911
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
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
Liabilities not subject to compromise
Long - term debt	6,335
Derivative liabilities	6,665
Asset retirement obligations	476
Total liabilities	33,349
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
Cancellation of Predecessor Common Stock
Equity:
Additional paid-in capital	288	[7]
Elimination of Predecessor Accumulated Deficit
Equity:
Additional paid-in capital	(1,636,890)	[8]
Retained earnings (accumulated deficit)	1,636,890	[8]
Revaluation of Assets and Liabilities
Equity:
Retained earnings (accumulated deficit)	(14,765)	[6]
Revaluation of Assets
Current assets:
Cash and cash equivalents	74,167	[3]
Liabilities subject to compromise
Accounts payable and other accrued liabilities	(2,560)	[3]
Equity:
Additional paid-in capital	100,084	[5]
Retained earnings (accumulated deficit)	166,144	[5]
Liabilities not subject to compromise
Accounts payable and other accrued liabilities	(1,981)	[6]
Settlement of Other Claims
Current assets:
Cash and cash equivalents	(24,204)	[2]
Liabilities not subject to compromise
Other accrued liabilities	(3,845)	[2]
Liabilities subject to compromise
Accounts payable and other accrued liabilities	(3,526)	[2]
Equity:
Common stock	20	[2]
Additional paid-in capital	1,318	[2]
Retained earnings (accumulated deficit)	2,188	[2]
Liabilities not subject to compromise
Accounts payable and other accrued liabilities	3,200	[6]
Revaluation of Liabilities
Current assets:
Cash and cash equivalents	(45,035)	[4]
Liabilities not subject to compromise
Other accrued liabilities	(1,500)	[4]
Trust Accounts
Current assets:
Cash and cash equivalents	(2,000)	[1]
Liabilities not subject to compromise
Other accrued liabilities	1,446	[1]
Discharge of Debt
Liabilities not subject to compromise
Other accrued liabilities	(2,685)	[5]
Equity:
Common stock	$ 1,457	[5]

[1] Reflects funding of the Recovery Trusts (see Note 9).

[2] Reflects settlement of other claims with common stock of Successor and cash. On the Emergence Date, we issued 1,919,733 shares of our common stock to various creditors. We estimated the fair value of our common stock to be $0.70 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.

[3] 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.

[4] 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.

[5] Reflects extinguishment of secured debt in exchange for common stock of the Successor. On the Emergence Date, we issued 145,736,082 shares of our common stock and warrants to acquire 9,592,125 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 $0.70 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.

[6] 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.

[7] Reflects cancellation of Predecessor common stock.

[8] Reflects elimination of Predecessor accumulated deficit.

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Acquisition (Tables)

12 Months Ended

Dec. 31, 2012

Summary of Fair Value of Assets Acquired and Liabilities Assumed

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

Intangible assets	$	8,809
Goodwill		7,756
Net non cash working capital		3,631
Deferred tax liabilities		(2,757	)
Total, net of cash acquired	$	17,439

Intangible Assets Estimated Amortization Expense

Estimated amortization expense is expected to be as follows (in thousands):

Year Ended
2013	$	2,008
2014		2,008
2015		908
2016		908
2017		908
Thereafter		2,069
	$	8,809

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Debt (Tables)

12 Months Ended

Dec. 31, 2012

Repayment of Premium Equal to Percentage of Principal Repaid

In addition to the above described prepayment premium, we will pay a repayment premium equal to the percentage of the principal repaid during the following periods:

Period	Repayment Premium
From the Emergence Date through the first anniversary of the Emergence Date		6	%
From the day after the first anniversary of the Emergence Date through the second anniversary of the Emergence Date		5	%
At all times from and after the day after the second anniversary of the Emergence Date		3	%

Long Term Debt

Our debt at December 31, 2012 is as follows (in thousands):

Tranche B Loan	$	35,000
Delayed Draw Term Loan Agreement		13,465
Less: unamortized debt discount – warrants		(6,014	)
Less: unamortized debt discount – embedded derivative		(60	)
Total debt, net of unamortized debt discount		42,391
Less: current maturities		(35,000	)
Long term debt, net of current maturities and unamortized discount	$	7,391

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Fresh Start Accounting and the Effects of the Plan

12 Months Ended

Dec. 31, 2012

Fresh Start Accounting and the Effects of the Plan

(2) Fresh Start Accounting and the Effects of the Plan

As required by U.S. generally accepted accounting principles (“U.S. GAAP”), effective as of August 31, 2012, Par adopted fresh start accounting following the guidance of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852 “Reorganizations” (“ASC 852”). Fresh start accounting 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 “Predecessor”) and are not comparable to the consolidated financial statements presented on or after August 31, 2012. Fresh start accounting 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 accounting 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 addition, the cancellation of debt income and the allocation of the attribute reduction for tax purposes is an estimate and will not be finalized until the 2012 tax return is filed sometime during 2013. Any change resulting from this estimate could impact deferred taxes.

Under ASC 852, 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 accounting, 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 7 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 accounting reflects the value of the Successor as determined in the confirmed Plan. Under fresh start accounting, our asset values are remeasured and allocated based on their respective fair values in conformity with the acquisition method of accounting for business combinations in FASB ASC Topic 805, “Business Combinations” (“ASC 805”). 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 section 1124(1) of 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 fresh start condensed consolidated balance sheet presents the implementation of the Plan and the adoption of fresh start accounting 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 accounting in accordance with ASC 852.

	August 31, 2012
	Predecessor			Plan of Reorganization Adjustments			Fresh Start Accounting Adjustments			Successor
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		0			3,446	(e)					3,446
Restricted cash		0			20,359	(d)					20,359
Trade accounts receivable, net		3,708			(1,727	)(a)		(1,981	)(g)		0
Prepaid assets		4,777						(4,777	)(g)		0
Prepaid reorganization costs		1,326						(1,326	)(g)		0
Total current assets		11,765									28,687
Property and equipment:
Oil and gas properties,
Unproved		84						(84	)(g)		0
Proved		759,755			(740,392	)(a)		(14,776	)(g)		4,587
Land		4,000			(4,000	)(a)					0
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)		0
Net property and equipment		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)				$	0
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)					0
7 % Senior convertible notes		150,000			(150,000	)(b)					0
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		0			6,335	(c)					6,335
Derivative liabilities		0			6,665	(c)					6,665
Asset retirement obligations		4,414			(3,938	)(a)					476
Total liabilities		357,273									33,349
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)		0
					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 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 extinguishment of secured debt in exchange for common stock of the Successor. On the Emergence Date, we issued 145,736,082 shares of our common stock and warrants to acquire 9,592,125 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 $0.70 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 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.

(d) Reflects settlement of other claims with common stock of Successor and cash. On the Emergence Date, we issued 1,919,733 shares of our common stock to various creditors. We estimated the fair value of our common stock to be $0.70 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 funding of the Recovery Trusts (see Note 9).

(f) Reflects cancellation of Predecessor common stock.

(g) 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.

(h) Reflects elimination of Predecessor accumulated deficit.

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Measurements Performed on Nonrecurring Basis

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

	Fair Value at August 31, 2012		Fair Value Technique
	(in thousands)
Oil and gas properties
Proved	$	4,587		(a	)(b)
Other assets
Frac tanks	$	1,400		(c	)
Compressors		2,800		(d	)
Miscellaneous		39		(e	)
	$	4,239
Investment in Piceance Energy	$	105,344		(f	)

(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 was valued using a market valuation technique which was based on published listings of similar equipment. We consider this to be a level 2 fair value measurement.

(d) The estimated fair value of the compressor units was valued using a market valuation technique based on standalone bids received by third-parties. We consider this to be a level 2 fair value measurement.

(e) 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.

(f) The estimated fair value of our investment in Piceance Energy is 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. A change in significant inputs such a reduction in commodity pricing or an increase in discount rates would result in a lower fair value.

Fair Values of Assets Acquired and Liabilities Assumed

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 (e) described below.

	Fair Value at December 31, 2012			Fair Value 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 shippers, 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.

Assets and Liabilities Measured at Fair Value on Recurring Basis

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 consist of the following (in thousands):

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

	Location on Consolidated Balance Sheet		Fair Value at December 31, 2012
			(in thousands)
Commodities – physical forward contracts		Prepaid and other current assets	$	(307	)
Commodities – exchange traded futures		Prepaid and other current assets	$	542
Warrant derivatives		Noncurrent liabilities	$	(10,900	)
Embedded derivative		Noncurrent liabilities	$	(45	)

Rollforward of Level Three Derivative Warrants and Embedded Derivative Measured at Fair Value on Recurring Basis

A rollforward of Level 3 derivative warrants and the embedded derivative measured at fair value using level 3 on a recurring basis is as follows (in thousands):

Description
Balance, at September 1, 2012	$	(6,665	)
Purchases, issuances, and settlements		—
Total unrealized losses included in earnings		(4,280	)
Transfers		—
Balance, at December 31, 2012	$	(10,945	)

Estimated Fair Value and Notional Amounts of Physical Forward Commodity Contracts

The estimated fair value and notional amounts of our open physical forward commodity contracts are shown in the table below (in thousands except volumes):

	Open Physical Forward Contracts
	December 31, 2012
				Notional Amounts
	Fair Value			Value		Volumes		Volume Unit		Maturity Dates
Crude oil	$	(227	)	WTI plus $	3.00		60,000		barrels		January 2013
Crude oil	$	(80	)	WTI plus $	15.00		21,497		barrels		January 2013

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Computation of Basic and Diluted Earnings Per Share (Detail) (USD $) Share data in Thousands, except Per Share data, unless otherwise specified	1 Months Ended		3 Months Ended		4 Months Ended	2 Months Ended		3 Months Ended												8 Months Ended	12 Months Ended
	Sep. 30, 2012 Successor		Dec. 31, 2012 Successor		Dec. 31, 2012 Successor	Aug. 31, 2012 Predecessor		Jun. 30, 2012 Predecessor		Mar. 31, 2012 Predecessor		Dec. 31, 2011 Predecessor		Sep. 30, 2011 Predecessor		Jun. 30, 2011 Predecessor		Mar. 31, 2011 Predecessor		Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Net loss attributable to common stockholders					$ (8,839,000)															$ (45,437,000)	$ (484,134,000)
Gain from discontinued operations, net of tax					0															0	14,023,000
Net loss attributable to common stockholders	$ (2,002,000)		$ (6,837,000)		$ (8,839,000)	$ (16,062,000)		$ (15,913,000)		$ (13,463,000)		$ (11,877,000)		$ (429,430,000)		$ (963,000)		$ (27,841,000)		$ (45,437,000)	$ (470,111,000)
Basic weighted-average common stock outstanding					157,335															28,841	28,841
Add: dilutive effects of stock options and unvested stock grants					0
Diluted weighted-average common stock outstanding					157,335															28,841	28,841
Basic loss per common share attributable to common stockholders:
Loss from continuing operations					$ (0.06)															$ (1.57)	$ (16.79)
Discontinued operations					$ 0.00															$ 0.00	$ 0.49
Net loss	$ (0.01)	[1]	$ (0.05)	[1]	$ (0.06)	$ (0.56)	[1]	$ (0.55)	[1]	$ (0.46)	[1]	$ (0.43)	[1]	$ (15.40)	[1]	$ (0.03)	[1]	$ (1.00)	[1]	$ (1.57)	$ (16.30)
Diluted loss per common share attributable to common stockholders:
Loss from continuing operations					$ (0.06)															$ (1.57)	$ (16.79)
Discontinued operations					$ 0.00															$ 0.00	$ 0.49
Net loss	$ (0.01)	[1]	$ (0.05)	[1]	$ (0.06)	$ (0.56)	[1]	$ (0.55)	[1]	$ (0.46)	[1]	$ (0.43)	[1]	$ (15.40)	[1]	$ (0.03)	[1]	$ (1.00)	[1]	$ (1.57)	$ (16.30)

[1] In preparing the December 31, 2012 financial statements, we recorded an immaterial correction of an error pursuant to FASB ASC Topic 250, Accounting Changes and Error Corrections. The errors related to the presentation of the gain on settlement of liabilities and fresh start accounting through the statement of equity as of September 1, 2012. As a result of application of the provisions of FASB ASC Topic 852, Reorganizations, the effect of the reorganization should have been reflected in the statement of operations of the Predecessor for the period from July 1 through August 31, 2012. The effect of the reorganization was previously disclosed in the footnotes to the Form 10-Q for the period ended September 30, 2012 and the Company believes the correction of this error is not material to its previously issued Predecessor financial statements. The Company has adjusted certain balances within the statement of operations and cash flows to correct this presentation error as follows: Predecessor Period from July 1, 2012 Through August 31, 2012 As reported Adjustments As Corrected (in thousands) Statement of Operations Loss from continuing operations before income taxes, reorganization items and discontinued operations $ (158,910 ) - $ (158,910 ) Reorganization items Professional fees and administrative costs (10,719 ) - (10,719 ) Gain on settlement of liabilities 168,332 168,332 Fresh Start Adjustments (14,765 ) (14,765 ) Net loss $ (169,629 ) $ 156,767 $ (16,062 ) Cash Flow Data Cash flow used in operations $ (17,863 ) $ (2,399 ) $ (20,262 ) Cash flow provided by investing activities (1,545 ) 74,167 72,622 Cash flow used in financing activities 8,500 (71,239 ) (60,340 )

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Information Regarding Proved Oil and Gas Reserves (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Changes in Estimated Quantities of Proved Reserves

A summary of changes in estimated quantities of proved reserves for respective periods in 2012 and for the year ended December 31, 2011 is as follows:

	Gas (MMcf)			Oil (MBbl)			NGLS (MBb1)			Total (MMcfe)  (6)
Company:
Estimated Proved Reserves: Balance at December 31, 2010 (Predecessor)		122,679			1,920			—			134,199
Revisions of quantity estimate (1)		(20,795	)		(232	)		—			(22,187	)
Extensions and discoveries		—			—			—			—
Purchase of properties		—			—			—			—
Sale of properties (2)		(4,259	)		(983	)		—			(10,157	)
Production		(10,416	)		(211	)		—			(11,682	)
Estimated Proved Reserves: Balance at December 31, 2011 (Predecessor) (5)		87,209			494			—			90,173
Revisions of quantity estimate		—			85			—			512
Extensions and discoveries		—			—			—			—
Purchase of properties		—			—			—			—
Sale/disposition of properties (3)		(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
Extensions and discoveries		—			—			—			—
Purchase of properties		—			—			—			—
Sale of properties		—			—			—			—
Production		(10	)		(22	)		—			(139	)
Estimated Proved Reserves: Balance at December 31, 2012 (Successor)		446			286			—			2,163
Company’s Share of Piceance Energy:
Estimated Proved Reserves: Balance at September 1, 2012		—			—			—			—
Transfer from investees (4)		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
Purchase of properties		—			—			—			—
Sale of properties		—			—			—			—
Production		(1,391	)		(6	)		(48	)		(1,711	)
Estimated Proved Reserves: Balance at December 31, 2012		122,650			831			6,345			165,700
Total Estimated Proved Reserves: Balance at December 31, 2012		123,096			1,117			6,345			167,863
Proved Developed reserves
December 31, 2011		87,209			494			—			90,173
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
December 31, 2011		—			—			—			—
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

	CIG per MMbtu		WTI per Bbl
Base Pricing, before adjustments for contractual differentials:
December 31, 2011	$	3.99	$	83.33
August 31, 2012	$	2.75	$	90.85
December 31, 2012	$	2.56	$	91.21
December 31, 2012 – Piceance Energy	$	2.56	$	91.21

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.

⁽¹⁾  During 2011, negative revisions were related to limited capital to develop reserves.

⁽²⁾ During 2011, proved reserves located in Texas, Colorado, and Wyoming were sold in conjunction with the Wapiti Transaction.

⁽³⁾ 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).

⁽⁴⁾ 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 4).

⁽⁵⁾  At December 31, 2011, 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.

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

Future Net Cash Flows

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, 2012			August 31, 2012			December 31, 2011
				(in thousands)
Company:
Future net cash flows	$	30,444		$	28,691		$	492,152
Future costs:
Production		20,596			19,973			252,532
Development and abandonment		319			319			319
Income taxes1		—			—			—
Future net cash flows		9,529			8,399			239,301
10% discount factor		(1,519	)		(1,176	)		(109,606	)
Standardized measure of discounted future net cash flows	$	8,010		$	7,223		$	129,695
Company’s Share of Piceance Energy:
Future net cash flows	$	568,706
Future costs:
Production		199,277
Development and abandonment		154,054
Income taxes1		—
Future net cash flows		215,375
10% discount factor		(143,416	)
Standardized measure of discounted future net cash flows	$	71,959
Total consolidated and equity investee interests in the standardized measure of discounted future net revenues	$	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.

Principal Sources of Changes in Standardized Measure of Discounted Net Cash Flows

The principal sources of changes in the standardized measure of discounted net cash flows for the respective periods during 2012 and for the year ended December 31, 2011 are as follows (in thousands):

	Successor									Predecessor
	Period from September 1, through December 31,			Company Share of Piceance Energy September 1, through December 31,			Total			Period from January 1, through August 31,			Year Ended December 31,
	2012			2012			2012			2012			2011
Beginning of the year										$	129,695		$	192,094
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	)		(42,187	)
Purchase of reserves in place		—			—			—			—			—
Net change in prices and production costs		(667	)		(139	)		(806	)		378			7,906
Changes in estimated future development costs		—			5			5			—			8,319
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	)		(17,130	)
Previously estimated development and abandonment costs incurred during the period		—			—			—			—			2,453
Sales/disposition of reserves in place		—			—			—			(118,104	)		(40,969	)
Change in future income tax		—			—			—			—			—
Other		258			4,360			4,618			—			—
Accretion of discount		241			1,842			2,083			8,647			19,209
													$	129,695
End of period	$	8,010		$	71,959		$	79,969		$	7,223

Reconciliation of PV-10 to Standardized Measure of Discounted Future Net Cash Flows

The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2012 (in thousands):

	Company		Company Share of Piceance Energy		Total
PV-10	$	8,010	$	71,959	$	79,969
Present value of future income taxes discounted at 10%		—		—		—
Standardized measure of discounted future net cash flows	$	8,010	$	71,959	$	79,969

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Summary of Fair Value of Assets Acquired and Liabilities Assumed (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Total, net of cash acquired	$ 17,439
Texadian Energy, Inc.
Intangible assets	8,809
Goodwill	7,756
Net non cash working capital	3,631
Deferred tax liabilities	(2,757)
Total, net of cash acquired	$ 17,439

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Summary of Claims (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Commitments and Contingencies [Line Items]
Reserve for contingent unliquidated claims	$ 10

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012 Successor		Dec. 31, 2011 Predecessor
Current assets:
Cash and cash equivalents	$ 6,185		$ 12,862
Restricted cash	23,970		0
Trade accounts receivable, net of allowance for doubtful accounts of $0 and $254, at December 31, 2012 and December 31, 2011, respectively	17,730		5,606
Prepaid and other current assets	1,575		3,399
Prepaid reorganization costs	0		1,301
Inventories	10,466		180
Total current assets	59,926		23,348
Oil and gas properties, at cost, successful efforts method of accounting:
Unproved	0		72,081
Proved	4,804		688,521
Land	0		4,000
Other	1,415		71,567
Total property and equipment	6,219		836,169
Less accumulated depreciation and depletion	(373)		(475,609)
Net property and equipment	5,846		360,560
Long-term assets:
Investments in unconsolidated affiliates	104,434		3,649
Intangible assets	8,809		0
Goodwill	7,756		0
Assets held for sale	2,800		0
Other long-term assets	11		340
Total long-term assets	123,810		3,989
Total assets	189,582	[1]	387,897
Current liabilities:
Debtor in possession financing	0		45,047
Current maturities of debt	35,000		0
Accounts payable	25,329		2,582
Other accrued liabilities	981		149
Accrued settlement claims	8,667		0
Accrued reorganization and trustee expense	0		851
7% Senior unsecured notes	0		150,000
3 3/4% Senior convertible notes	0		115,000
Accounts payable	0		13,597
Other accrued liabilities			6,939
Total current liabilities	69,977		334,165
Long-term liabilities:
Long - term debt, net of current maturities and unamortized discount	7,391		0
Derivative liabilities	10,945		0
Asset retirement obligations	512		3,507
Total liabilities	88,825		337,672
Commitments and contingencies
Stockholders' Equity:
Preferred stock, $0.01 par value: authorized 3,000,000 shares, none issued	0		0
Common stock, $0.01 par value; authorized 300,000,000 shares and 200,000,000 shares at December 31, 2012 and December 31, 2011, respectively, issued 150,080,927 shares and 28,841,177 shares at December 31, 2012 and December 31, 2011, respectively	1,501		288
Additional paid-in capital	108,095		1,641,390
Accumulated deficit	(8,839)		(1,591,453)
Total stockholders' equity	100,757	[1]	50,225
Total liabilities and stockholders' equity	$ 189,582		$ 387,897

[1] Reflects true-up adjustments to the preliminary fresh start accounting values recorded at September 30, 2012. Predecessor Quarter Ended March 31, June 30, September 30, December 31, (In thousands, except per share amounts) Year Ended December 31, 2011 (Predecessor) Total revenue $ 17,715 $ 16,882 $ 16,546 $ 12,737 Loss from continuing operations before income taxes, discontinued operations and cumulative effect (27,424 ) (12,724 ) (429,973 ) (17,411 ) Net loss (27,841 ) (963 ) (429,430 ) (11,877 ) Net income (loss) per common share:(1) Basic $ (1.00 ) $ (.03 ) $ (15.40 ) $ (.43 ) Diluted $ (1.00 ) $ (.03 ) $ (15.40 ) $ (.43 )

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Fresh Start Condensed Consolidated Balance Sheet (Parenthetical) (Detail) (USD $)	8 Months Ended					8 Months Ended
	Aug. 31, 2012	Dec. 31, 2012	Dec. 31, 2012 Piceance Energy	Aug. 31, 2012 Piceance Energy	Jun. 04, 2012 Piceance Energy	Aug. 31, 2012 Extinguishment of secured debt	Aug. 31, 2012 Settlement of Other Claims	Aug. 31, 2012 Reorganized Delta Petroleum	Jun. 04, 2012 Reorganized Delta Petroleum	Jun. 04, 2012 Reorganized Delta Petroleum Piceance Energy
Reorganization [Line Items]
Equity method investment ownership percentage			33.34%	33.34%				33.34%		33.34%
Common stock shares issued		147,700,000				145,736,082	1,919,733
Warrants to purchase shares of common stock		9,592,125				9,592,125
Fair value of common stock per share		$ 0.70				$ 0.70	$ 0.70
Gain on settlement of debt						$ 166,100,000	$ 2,200,000
Amount borrowed under new credit agreement					100,000,000			13,000,000	13,000,000
Loss for change in fair value of assets	$ 4,800,000

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Future Net Cash Flows (Detail) (USD $) In Thousands, unless otherwise specified	4 Months Ended								8 Months Ended		12 Months Ended		8 Months Ended		12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 Company	Dec. 31, 2012 Company's Share of Piceance Energy	Dec. 31, 2012 Successor	Dec. 31, 2012 Successor Company		Dec. 31, 2012 Successor Company's Share of Piceance Energy		Aug. 31, 2012 Predecessor Company		Dec. 31, 2011 Predecessor Company		Aug. 31, 2012 Predecessor Company's Share of Piceance Energy		Dec. 31, 2011 Predecessor Company's Share of Piceance Energy
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future net cash flows	$ 79,969	$ 8,010	$ 71,959		$ 30,444		$ 568,706		$ 28,691		$ 492,152
Future costs: Production					20,596		199,277		19,973		252,532
Future costs: Development and abandonment					319		154,054		319		319
Income taxes						[1]		[1]		[1]		[1]		[1]		[1]
Future net cash flows					9,529		215,375		8,399		239,301
10% discount factor					(1,519)		(143,416)		(1,176)		(109,606)
Standardized measure of discounted future net cash flows				$ 79,969	$ 8,010		$ 71,959		$ 7,223		$ 129,695

[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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Consolidated Statements Of Cash Flows (USD $)	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2011 Predecessor Texadian Energy, Inc.	Dec. 31, 2011 Predecessor Letter of Credit
Cash flows from operating activities:
Net loss	$ (8,839,000)	$ (45,437,000)	$ (470,040,000)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion - oil and gas	401,000	16,041,000	39,082,000
Depreciation, depletion, amortization - discontinued operations	0	0	5,348,000
Interest capitalized into note balance	465,000	2,989,000	74,000
Change in asset values due to fresh start accounting adjustments	0	14,765,000	0
Gain on extinguishment of senior debt	0	(166,144,000)	0
Gain on settlement of liabilities		(2,188,000)
Gain on sale of assets - discontinued operations	0	0	(14,699,000)
(Gain) loss on property sales	(82,000)	126,000	85,000
Dry hole costs and impairments	0	151,347,000	420,402,000
Impairments - discontinued operations			608,000
Stock-based compensation	34,000	1,895,000	8,003,000
Amortization of deferred financing costs, bond discount, and installments payable discount	591,000	0	13,805,000
Accretion of discount in installments payable			2,126,000
Increase in allowance for bad debt			154,000
Unrealized loss (gain) on derivative contracts	4,280,000	0	(2,993,000)
(Income) loss from unconsolidated affiliates	1,325,000	20,000	344,000
Deferred income tax expense (benefit)	(2,757,000)	0	956,000
Other	0	(699,000)	1,940,000
Net changes in operating assets and liabilities:
Trade accounts receivable	(2,234,000)	3,472,000	1,535,000
Deposits and prepaid assets	(538,000)	(1,378,000)	(3,018,000)
Inventories	0	0	(68,000)
Other current assets	0	0	(285,000)
Accounts payable	2,718,000	(4,187,000)	861,000
Accrued reorganization costs	0	9,116,000	851,000
Other accrued liabilities	0	0	(3,722,000)
Assets held for sale working capital, net	0	0	(359,000)
Net cash provided by (used in) operating activities	(4,636,000)	(20,262,000)	990,000
Cash flows from investing activities:
Additions to property and equipment	0	(1,613,000)	(56,058,000)
Additions to drilling and trucking equipment - assets held for sale	0	0	(1,529,000)
Acquisition of Texadian, net of cash acquired				0
Decrease in restricted deposit	0	0	100,000,000
Proceeds from the sale of oil and gas properties	0	74,209,000	40,229,000
Proceeds from sale of drilling assets - assets held for sale	0	0	3,429,000
Proceeds from sale of other fixed assets	39,000	26,000	0
Proceeds from sale of marketable securities	0	0	61,000
Capitalized drilling costs owed to operator	(415,000)	0	0
Proceeds from sale of unconsolidated affiliates	125,000	0	1,517,000
Net cash provided by (used in) investing activities	(17,690,000)	72,622,000	87,649,000
Cash flows from financing activities:
Proceeds from borrowings	35,000,000	23,000,000	117,550,000
Repayments of borrowings	0	(59,535,000)	(104,992,000)
Fund distribution agent account	0	(21,805,000)	0
Proceeds from (funding of) Wapiti and General Recovery Trusts	2,446,000	(2,000,000)	0
Installments paid of property acquisitions	0		(100,000,000)
Recoveries from bankruptcy settlements	5,183,000	0	0
Restricted cash held to secure letter of credits					0
Payment of deferred financing costs	0	0	(1,529,000)
Stock repurchased for withholding taxes	0	0	(996,000)
Net cash provided by (used in) financing activities	23,629,000	(60,340,000)	(89,967,000)
Net increase (decrease) in cash and cash equivalents	1,303,000	(7,980,000)	(1,328,000)
Cash at beginning of period	4,882,000	12,862,000	14,190,000
Cash at end of period	6,185,000	4,882,000	12,862,000
Supplemental cash flow information:
Cash paid for interest and financing costs	0	3,745,000	19,384,000
Non-cash investing and financing activities:
Interest payable capitalized to principal balance	0	0	5,573,000
Non-cash additions to oil and gas properties	$ 209,000	$ 0	$ 0

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Changes in Estimated Quantities of Proved Reserves (Detail)	4 Months Ended		8 Months Ended		12 Months Ended
	Dec. 31, 2012 MMcf		Aug. 31, 2012		Dec. 31, 2011 MMcf
Reserve Quantities [Line Items]
Ending Balance	167,863	[1]
Proved developed reserve	65,492	[1]
Proved undeveloped reserve	102,371	[1]
Natural Gas
Reserve Quantities [Line Items]
Ending Balance	123,096
Proved developed reserve	48,838
Proved undeveloped reserve	74,258
Natural Gas Liquids
Reserve Quantities [Line Items]
Ending Balance	6,345,000
Proved developed reserve	2,253,000
Proved undeveloped reserve	4,092,000
Oil
Reserve Quantities [Line Items]
Ending Balance	1,117,000
Proved developed reserve	523,000
Proved undeveloped reserve	594,000
Company
Reserve Quantities [Line Items]
Proved developed reserve	1,875	[1]			90,173	[1]
Proved undeveloped reserve	288	[1]
Company | Predecessor
Reserve Quantities [Line Items]
Beginning Balance			90,173	[1],[2]	134,199	[1]
Revisions of quantity estimate			512	[1]	(22,187)	[1],[3]
Purchase of properties				[1]		[1]
Sale/disposition of properties			(83,770)	[1],[4]	(10,157)	[1],[5]
Production			(5,256)	[1]	(11,682)	[1]
Ending Balance					90,173	[1],[2]
Company | Successor
Reserve Quantities [Line Items]
Beginning Balance	1,659	[1]
Revisions of quantity estimate	643	[1]
Purchase of properties		[1]
Production	(139)	[1]
Ending Balance	2,163	[1]
Company | Natural Gas
Reserve Quantities [Line Items]
Proved developed reserve	158				87,209
Proved undeveloped reserve	288
Base Pricing, before adjustments for contractual differentials	2.56		2.75		3.99
Company | Natural Gas | Predecessor
Reserve Quantities [Line Items]
Beginning Balance			87,209	[2]	122,679
Revisions of quantity estimate					(20,795)	[3]
Purchase of properties
Sale/disposition of properties			(82,357)	[4]	(4,259)	[5]
Production			(4,852)		(10,416)
Ending Balance					87,209	[2]
Company | Natural Gas | Successor
Reserve Quantities [Line Items]
Revisions of quantity estimate	456
Purchase of properties
Production	(10)
Ending Balance	446
Company | Natural Gas Liquids | Predecessor
Reserve Quantities [Line Items]
Purchase of properties
Company | Natural Gas Liquids | Successor
Reserve Quantities [Line Items]
Purchase of properties
Company | Oil
Reserve Quantities [Line Items]
Proved developed reserve	286,000				494,000
Base Pricing, before adjustments for contractual differentials	91.21		90.85		83.33
Company | Oil | Predecessor
Reserve Quantities [Line Items]
Beginning Balance			494,000	[2]	1,920,000
Revisions of quantity estimate			85,000		(232,000)	[3]
Purchase of properties
Sale/disposition of properties			(235,000)	[4]	(983,000)	[5]
Production			(67,000)		(211,000)
Ending Balance					494,000	[2]
Company | Oil | Successor
Reserve Quantities [Line Items]
Beginning Balance	277,000
Revisions of quantity estimate	31,000
Purchase of properties
Production	(22,000)
Ending Balance	286,000
Company's Share of Piceance Energy
Reserve Quantities [Line Items]
Revisions of quantity estimate	10,621	[1]
Extensions and discoveries	44,151	[1]
Purchase of properties		[1]
Production	(1,711)	[1]
Ending Balance	165,700	[1]
Transfer from investees	112,639	[1],[6]
Proved developed reserve	63,617	[1]
Proved undeveloped reserve	102,083	[1]
Company's Share of Piceance Energy | Natural Gas
Reserve Quantities [Line Items]
Revisions of quantity estimate	8,053
Extensions and discoveries	32,073
Purchase of properties
Production	(1,391)
Ending Balance	122,650
Transfer from investees	83,915	[6]
Proved developed reserve	48,680
Proved undeveloped reserve	73,970
Base Pricing, before adjustments for contractual differentials	2.56
Company's Share of Piceance Energy | Natural Gas Liquids
Reserve Quantities [Line Items]
Revisions of quantity estimate	387,000
Extensions and discoveries	1,778,000
Purchase of properties
Production	(48,000)
Ending Balance	6,345,000
Transfer from investees	4,228,000	[6]
Proved developed reserve	2,253,000
Proved undeveloped reserve	4,092,000
Company's Share of Piceance Energy | Oil
Reserve Quantities [Line Items]
Revisions of quantity estimate	41,000
Extensions and discoveries	236,000
Purchase of properties
Production	(6,000)
Ending Balance	831,000
Transfer from investees	560,000	[6]
Proved developed reserve	237,000
Proved undeveloped reserve	594,000
Base Pricing, before adjustments for contractual differentials	91.21

[1] MMcfe is based on a ratio of 6 Mcf to 1 barrel.

[2] At December 31, 2011, 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.

[3] During 2011, negative revisions were related to limited capital to develop reserves.

[4] 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).

[5] During 2011, proved reserves located in Texas, Colorado, and Wyoming were sold in conjunction with the Wapiti Transaction.

[6] 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 4).

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Fair Value Measurements Performed on Nonrecurring Basis (Parenthetical) (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Aug. 31, 2012
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Cash flow model discount rate	15.40%
Piceance Energy
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Equity method investment ownership percentage	33.34%	33.34%
Investment in Piceance Energy		$ 105,344
Fair Value, Measurements, Nonrecurring | Piceance Energy
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Equity method investment ownership percentage		33.34%
Investment in Piceance Energy		$ 105,344	[1]
Fair Value, Measurements, Nonrecurring | Proved Developed and Producing Reserves
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Cash flow model discount rate		10.00%
Fair Value, Measurements, Nonrecurring | Proved Developed Non Producing Reserves
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Cash flow model discount rate		15.00%
Fair Value, Measurements, Nonrecurring | Proved Undeveloped Reserves
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Cash flow model discount rate		20.00%

[1] The estimated fair value of our investment in Piceance Energy is 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. A change in significant inputs such a reduction in commodity pricing or an increase in discount rates would result in a lower fair value.

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Reconciliation of PV-10 to Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail)	Dec. 31, 2012
Present value of future income taxes, discount rate	10.00%
Company
Present value of future income taxes, discount rate	10.00%
Company's Share of Piceance Energy
Present value of future income taxes, discount rate	10.00%

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Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2012

Incentive Plan Activity

For the period from September 1, 2012 through December 31, 2012, the following activity occurred under our Incentive Plan:

	Shares		Weighted-Average Grant Date Fair Value
Stock Awards
Non vested balance, beginning of period		—		—
Granted		2,191,834	$	1.09
Vested		—		—
Forfeited		—		—
Non vested balance, end of period		2,191,834	$	1.09

Summary of Stock Option Activity under Predecessor's Various Plans and Related Information

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 and for the year ended December 31, 2011 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		0		$	0			0		0
Exercisable-end of year		0		$	0			0		0

	Year Ended December 31, 2011
	Options			Weighted-Average Exercise Price			Weighted-Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding-beginning of year		160,800		$	72.60
Granted		—			—
Exercised		—			—
Expired		(10,500	)		(38.96	)
Outstanding-end of year		150,300		$	75.00			2.64 years		—
Exercisable-end of year		150,300		$	75.00			2.64 years		—

Summary of Restricted Stock (Nonvested Stock) Activity under Predecessor's Plan and Related Information

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 and for the year ended December 31, 2011 follows (in thousands accept 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		0			0
Vested		0			0
Expired / canceled		(558,301	)		(7.45	)
Nonvested-end of year		0		$	0			0	$	0

	Year Ended December 31, 2011
	Nonvested Stock			Weighted-Average Grant-Date Fair Value			Weighted-Average Remaining Contractual Term		Aggregate Intrinsic Value
Nonvested-beginning of year		734,376		$	15.27
Granted		598,836			5.92
Vested		(719,350	)		(11.74	)
Expired / Forfeited		(55,561	)		(36.22	)
Nonvested-end of year		558,301		$	7.45			0.48 years	$	3,307

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Estimated Fair Value and Notional Amounts of Physical Forward Commodity Contracts (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 bbl
Fair Value of Derivative Instruments [Line Items]
Volumes	10,000
Physical Forward Contracts | Crude Oil | Product 1
Fair Value of Derivative Instruments [Line Items]
Fair Value	$ (227)
Notional Amounts Value	WTI plus $ 3.00
Volumes	60,000
Maturity Dates	2013-01
Physical Forward Contracts | Crude Oil | Product 2
Fair Value of Derivative Instruments [Line Items]
Fair Value	$ (80)
Notional Amounts Value	WTI plus $ 15.00
Volumes	21,497
Maturity Dates	2013-01

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Information Regarding Proved Oil and Gas Reserves (Unaudited)

12 Months Ended

Dec. 31, 2012

Information Regarding Proved Oil and Gas Reserves (Unaudited)

(16) 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, reserves estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.

Proved Oil and Gas Reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices using the 12-month historical first of month average and costs as of the date the estimate was made for all years presented. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic productability is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves;” (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids that may occur in underlaid prospects; and (D) crude oil, natural gas, and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped oil and gas reserves are reserves 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved 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 tests in the area and in the same reservoir.

“Prepared” reserves are those quantities of reserves which were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of revenues which were estimated by the Company’s employees and audited by an independent petroleum consultant. An audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been determined using methods and procedures widely accepted within the industry and in accordance with SEC rules.

Estimates of the Company’s oil and natural gas reserves and present values as of December 31, 2012, August 31, 2012 and December 31, 2011 were prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers.

A summary of changes in estimated quantities of proved reserves for respective periods in 2012 and for the year ended December 31, 2011 is as follows:

	Gas (MMcf)			Oil (MBbl)			NGLS (MBb1)			Total (MMcfe)  (6)
Company:
Estimated Proved Reserves: Balance at December 31, 2010 (Predecessor)		122,679			1,920			—			134,199
Revisions of quantity estimate (1)		(20,795	)		(232	)		—			(22,187	)
Extensions and discoveries		—			—			—			—
Purchase of properties		—			—			—			—
Sale of properties (2)		(4,259	)		(983	)		—			(10,157	)
Production		(10,416	)		(211	)		—			(11,682	)
Estimated Proved Reserves: Balance at December 31, 2011 (Predecessor) (5)		87,209			494			—			90,173
Revisions of quantity estimate		—			85			—			512
Extensions and discoveries		—			—			—			—
Purchase of properties		—			—			—			—
Sale/disposition of properties (3)		(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
Extensions and discoveries		—			—			—			—
Purchase of properties		—			—			—			—
Sale of properties		—			—			—			—
Production		(10	)		(22	)		—			(139	)
Estimated Proved Reserves: Balance at December 31, 2012 (Successor)		446			286			—			2,163
Company’s Share of Piceance Energy:
Estimated Proved Reserves: Balance at September 1, 2012		—			—			—			—
Transfer from investees (4)		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
Purchase of properties		—			—			—			—
Sale of properties		—			—			—			—
Production		(1,391	)		(6	)		(48	)		(1,711	)
Estimated Proved Reserves: Balance at December 31, 2012		122,650			831			6,345			165,700
Total Estimated Proved Reserves: Balance at December 31, 2012		123,096			1,117			6,345			167,863
Proved Developed reserves
December 31, 2011		87,209			494			—			90,173
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
December 31, 2011		—			—			—			—
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

	CIG per MMbtu		WTI per Bbl
Base Pricing, before adjustments for contractual differentials:
December 31, 2011	$	3.99	$	83.33
August 31, 2012	$	2.75	$	90.85
December 31, 2012	$	2.56	$	91.21
December 31, 2012 – Piceance Energy	$	2.56	$	91.21

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.

⁽¹⁾  During 2011, negative revisions were related to limited capital to develop reserves.

⁽²⁾ During 2011, proved reserves located in Texas, Colorado, and Wyoming were sold in conjunction with the Wapiti Transaction.

⁽³⁾ 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).

⁽⁴⁾ 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 4).

⁽⁵⁾  At December 31, 2011, 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.

⁽⁶⁾  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, 2012			August 31, 2012			December 31, 2011
				(in thousands)
Company:
Future net cash flows	$	30,444		$	28,691		$	492,152
Future costs:
Production		20,596			19,973			252,532
Development and abandonment		319			319			319
Income taxes1		—			—			—
Future net cash flows		9,529			8,399			239,301
10% discount factor		(1,519	)		(1,176	)		(109,606	)
Standardized measure of discounted future net cash flows	$	8,010		$	7,223		$	129,695
Company’s Share of Piceance Energy:
Future net cash flows	$	568,706
Future costs:
Production		199,277
Development and abandonment		154,054
Income taxes1		—
Future net cash flows		215,375
10% discount factor		(143,416	)
Standardized measure of discounted future net cash flows	$	71,959
Total consolidated and equity investee interests in the standardized measure of discounted future net revenues	$	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 respective periods during 2012 and for the year ended December 31, 2011 are as follows (in thousands):

	Successor									Predecessor
	Period from September 1, through December 31,			Company Share of Piceance Energy September 1, through December 31,			Total			Period from January 1, through August 31,			Year Ended December 31,
	2012			2012			2012			2012			2011
Beginning of the year										$	129,695		$	192,094
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	)		(42,187	)
Purchase of reserves in place		—			—			—			—			—
Net change in prices and production costs		(667	)		(139	)		(806	)		378			7,906
Changes in estimated future development costs		—			5			5			—			8,319
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	)		(17,130	)
Previously estimated development and abandonment costs incurred during the period		—			—			—			—			2,453
Sales/disposition of reserves in place		—			—			—			(118,104	)		(40,969	)
Change in future income tax		—			—			—			—			—
Other		258			4,360			4,618			—			—
Accretion of discount		241			1,842			2,083			8,647			19,209
													$	129,695
End of period	$	8,010		$	71,959		$	79,969		$	7,223

Reconciliation of PV-10 to Standardized Measure

PV-10 is the estimated present value of the future net revenues from our 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 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. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. 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, 2012 (in thousands):

	Company		Company Share of Piceance Energy		Total
PV-10	$	8,010	$	71,959	$	79,969
Present value of future income taxes discounted at 10%		—		—		—
Standardized measure of discounted future net cash flows	$	8,010	$	71,959	$	79,969

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Expense (Benefit) Attributable to Income from Continuing Operations

Income tax expense (benefit) attributable to income from continuing operations consisted of the following:

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012		Year Ended December 31, 2011
Current:
U.S.—Federal	$	—			0	$	—
U.S.—State		—			0		—
Foreign		—			0		—
Deferred:
U.S.—Federal		(2,757	)		0		(4,329	)
U.S.—State		—			0		—
Total	$	(2,757	)	$	0	$	(4,329	)

Income Tax Expense Attributable to Income from Continuing Operations

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

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Federal statutory rate		(35.0	)%		(35.0	)%		(35.0	)%
State income taxes, net of federal benefit		0			0			(1.9	)
Change in valuation allowance		(2.0	)		(33.0)			34.3
Professional fees related to bankruptcy reorganization		8.0			17.0			1.8
Revenue from Wapiti Trust settlement		5			0			0
Cancellation of debt tax attribute reduction		0			51			0
Actual income tax rate		(24.0	)%		—	%		(0.8)	%

Deferred Tax Assets Liabilities

Deferred tax assets (liabilities) are comprised of the following at December 31, 2012 and 2011 (in thousands):

	2012			2011
Deferred tax assets:
Net operating loss	$	450,195		$	450,632
Capital loss carry forwards		26,141			35,919
Asset retirement obligation		179			1,398
Property and equipment		23,045			39,912
Investment in Piceance Energy		45,172			—
Equity compensation		—			10,448
Equity investments		—			329
Derivative instruments		1,498			—
Minimum tax credit		785			1,045
Contribution carryforwards		189			517
Accrued bonuses		—			517
Allowance for doubtful accounts		—			93
Accrued vacation		—			125
Texadian Energy		326			—
Other		27			69
Total deferred tax assets		547,557			541,004
Valuation allowance		(544,442	)		(540,724	)
Net deferred tax assets	$	3,115		$	280
Deferred tax liabilities:
Property and equipment	$	—		$	—
Texadian Energy intangibles		3,083
Prepaid insurance, marketable securities and other		32			280
Total deferred tax liabilities	$	3,115		$	280
Total deferred taxes, net	$	0		$	0

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Reconciliation of PV-10 to Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $) In Thousands, unless otherwise specified	4 Months Ended
	Dec. 31, 2012
PV-10	$ 79,969
Present value of future income taxes discounted at 10%
Standardized measure of discounted future net cash flows	79,969
Company
PV-10	8,010
Present value of future income taxes discounted at 10%
Standardized measure of discounted future net cash flows	8,010
Company's Share of Piceance Energy
PV-10	71,959
Present value of future income taxes discounted at 10%
Standardized measure of discounted future net cash flows	$ 71,959

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Related Party Transactions

12 Months Ended

Dec. 31, 2012

Related Party Transactions

(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 6).

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Oil and Gas Segment and Drilling Segment Revenues and Expenses Included In Discontinued Operations (Detail) (USD $)	4 Months Ended	2 Months Ended	3 Months Ended						8 Months Ended	12 Months Ended
	Dec. 31, 2012	Aug. 31, 2012 Predecessor	Jun. 30, 2012 Predecessor	Mar. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor	Sep. 30, 2011 Predecessor	Jun. 30, 2011 Predecessor	Mar. 31, 2011 Predecessor	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor	Dec. 31, 2011 Discontinued Operations Predecessor		Dec. 31, 2011 Discontinued Operations Predecessor Oil & Gas		Dec. 31, 2011 Discontinued Operations Predecessor Drilling
Revenues:
Oil and gas sales		$ 5,466,000	$ 7,703,000	$ 9,910,000	$ 12,737,000	$ 16,546,000	$ 16,882,000	$ 17,715,000	$ 23,079,000	$ 63,880,000	$ 10,276,000		$ 10,276,000
Contract drilling and trucking fees											45,241,000				45,241,000
Total Revenues											55,517,000		10,276,000		45,241,000
Operating Expenses:
Lease operating expense									9,038,000	13,755,000	2,482,000		2,482,000
Transportation expense									6,963,000	13,867,000	16,000		16,000
Production taxes									979,000	1,535,000	370,000		370,000
Dry hole costs and impairments									151,347,000	420,402,000	608,000	[1]	608,000	[1]
Depreciation, depletion, amortization and accretion - oil and gas											2,796,000		2,796,000
Drilling and trucking operating expenses											35,617,000				35,617,000
Depreciation and amortization - drilling and trucking											2,669,000	[2]			2,669,000	[2]
General and administrative expense									9,386,000	28,124,000	3,014,000				3,014,000
Total operating expenses									193,756,000	517,109,000	47,572,000		6,272,000		41,300,000
Operating income (loss)									(170,677,000)	(453,229,000)	7,945,000		4,004,000		3,941,000
Other income and (expense):
Interest expense and financing costs, net	(1,056,000)								(6,852,000)	(32,324,000)	(6,911,000)				(6,911,000)
Other income									516,000	(1,947,000)	2,734,000				2,734,000
Total other expense									(6,356,000)	(34,302,000)	(4,177,000)				(4,177,000)
Income (loss) from discontinued operations											3,768,000		4,004,000		(236,000)
Income tax expense											(1,724,000)	[3]	(1,724,000)	[3]
Income (loss) from results of operations of discontinued operations, net of tax									0	14,699,000	2,044,000		2,280,000		(236,000)
Gain on sales of discontinued operations, net of tax											12,050,000	[4]	6,874,000	[4]	5,176,000	[4]
Income from results of discontinued operations of oil and gas producing activities									$ 0	$ 14,094,000	$ 14,094,000		$ 9,154,000		$ 4,940,000

[1] Dry Hole Costs and Impairments. In 2011, we recorded impairments on our Columbia River, Greentown and Gulf Coast properties of $491,000 prior to their sale. In accordance with accounting standards, the impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction with the Wapiti Transaction were reflected as discontinued operations.

[2] Depreciation and Amortization - Drilling and Trucking. Depreciation and amortization- drilling and trucking was $2.7 million for the year ended December 31, 2011. We stopped recording depreciation expense beginning in March 2011 in accordance with accounting rules related to the asset held for sale treatment of DHS.

[3] Income tax expense. For the year ended December 31, 2011, we recorded a tax benefit of approximately $1.2 million due to a non-cash income tax benefit related to gains from discontinued oil and gas operations. U.S. GAAP requires all items be considered, including items recorded in discontinued operations, in determining the amount of tax benefit that results from a loss from continuing operations that should be allocated to continuing operations. In accordance with U.S. GAAP, we recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations.

[4] Gain on sales of discontinued operations - oil and gas. In accordance with U.S. GAAP, we recognized a $5.6 million gain on sale ($8.9 million gain, net of $3.3 million of tax) for the year ended December 31, 2011 that is reflected in discontinued operations. In June 2011, DHS sold certain of its trucking assets for $3.3 million in proceeds and a gain of $2.9 million.

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Reorganization under Chapter 11

12 Months Ended

Dec. 31, 2012

Reorganization under Chapter 11

(1) Reorganization under Chapter 11

On December 16, 2011, Delta Petroleum Corporation (“Delta”) and its subsidiaries Amber Resources Company of Colorado, DPCA, LLC, Delta Exploration Company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc. and Castle Texas Production Limited Partnership 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”). On January 6, 2012, Castle Exploration Company, Inc., a subsidiary of Delta Pipeline, LLC, also filed a voluntary petition under Chapter 11 in the Bankruptcy Court. Delta and its subsidiaries included in the bankruptcy petitions are collectively referred to as the “Debtors.”

On December 27, 2011, the Debtors filed a motion requesting an order to approve matters relating to a proposed sale of Delta’s assets, including bidding procedures, establishment of a sale auction date and establishment of a sale hearing date. On January 11, 2012, the Bankruptcy Court issued an order approving these matters. On March 20, 2012, Delta announced that it was seeking court approval to amend the bidding procedures for its upcoming auction to allow bids relating to potential plans of reorganization as well as asset sales. On March 22, 2012, the Bankruptcy Court approved the revised procedures.

Following the auction, 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 connection with the Plan, Delta entered into a non-binding term sheet describing a transaction by which Laramie and Delta intended to form a new joint venture called Piceance Energy LLC (“Piceance Energy”). On June 4, 2012, Delta entered into a Contribution Agreement (the “Contribution Agreement”) with Piceance Energy and Laramie to effect the transactions contemplated by the term sheet.

On June 4, 2012, the Debtors filed a disclosure statement relating to the Plan. The Plan was confirmed on August 15, 2012 and 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 (referred to after the closing of the transaction as “Successor”). 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.

On the Emergence Date, Delta also amended and restated its certificate of incorporation and bylaws and changed its name to Par Petroleum Company (“Par”). The amended and restated certificate of incorporation contains restrictions that render void certain transfers of the Company 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 the Company believes may have value. Under the amended and restated bylaws, the Company board of directors has five members, each of whom was appointed by its stockholders pursuant to a Stockholders’ Agreement entered into on the Emergence Date.

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 147.7 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.

In addition, Laramie and Piceance Energy entered into a Management Services Agreement pursuant to which Laramie agreed to provide certain services to Piceance Energy for a fee of $650,000 per month.

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2012 Successor	Dec. 31, 2011 Predecessor	Dec. 31, 2012 Senior notes Successor	Dec. 31, 2011 Senior notes Predecessor	Dec. 31, 2012 Senior convertible notes Successor	Dec. 31, 2011 Senior convertible notes Predecessor
Allowance for doubtful accounts	$ 0	$ 254
Interest rate on long term debt			7.00%	7.00%	3.75%	3.75%
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	3,000,000	3,000,000
Preferred stock, shares issued
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	300,000,000	200,000,000
Common stock, shares issued	150,080,927	28,841,177

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Taxes

(11) Income Taxes

Under the Plan, the Company’s 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 NOL’s 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. The Company’s NOLs have been reduced by approximately $230 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 place restrictions upon the ability of the equity interest holders to transfer their ownership in the Company. 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 continues to conclude 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 our net deferred tax assets at December 31, 2012.

As of December 31, 2012, our deferred tax assets exceeded deferred tax liabilities. Accordingly, based on significant recent operating losses other than the non-recurring taxable income resulting from the Contribution Agreement, and projections for future results, a valuation allowance has been recorded for our net deferred tax assets.

During the year ended December 31, 2011, the periods from January 1 through August 31, 2012, and the period from September 1 through December 31, 2012, no adjustments were recognized for uncertain tax benefits.

During 2013 and thereafter, we will continue to assess the realizability of its 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) attributable to income from continuing operations consisted of the following:

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012		Year Ended December 31, 2011
Current:
U.S.—Federal	$	—			0	$	—
U.S.—State		—			0		—
Foreign		—			0		—
Deferred:
U.S.—Federal		(2,757	)		0		(4,329	)
U.S.—State		—			0		—
Total	$	(2,757	)	$	0	$	(4,329	)

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

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Federal statutory rate		(35.0	)%		(35.0	)%		(35.0	)%
State income taxes, net of federal benefit		0			0			(1.9	)
Change in valuation allowance		(2.0	)		(33.0)			34.3
Professional fees related to bankruptcy reorganization		8.0			17.0			1.8
Revenue from Wapiti Trust settlement		5			0			0
Cancellation of debt tax attribute reduction		0			51			0
Actual income tax rate		(24.0	)%		—	%		(0.8	)%

For the year ended December 31, 2011, the Predecessor recorded a tax benefit of $5.0 million due to a non-cash income tax benefit related to gains from discontinued oil and gas operations. U.S. GAAP requires all items be considered, including items recorded in discontinued operations, in determining the amount of tax benefit that results from a loss from continuing operations that should be allocated to continuing operations. In accordance with U.S. GAAP, we recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations.

Deferred tax assets (liabilities) are comprised of the following at December 31, 2012 and 2011 (in thousands):

	2012			2011
Deferred tax assets:
Net operating loss	$	450,195		$	450,632
Capital loss carry forwards		26,141			35,919
Asset retirement obligation		179			1,398
Property and equipment		23,045			39,912
Investment in Piceance Energy		45,172			—
Equity compensation		—			10,448
Equity investments		—			329
Derivative instruments		1,498			—
Minimum tax credit		785			1,045
Contribution carryforwards		189			517
Accrued bonuses		—			517
Allowance for doubtful accounts		—			93
Accrued vacation		—			125
Texadian Energy		326			—
Other		27			69
Total deferred tax assets		547,557			541,004
Valuation allowance		(544,442	)		(540,724	)
Net deferred tax assets	$	3,115		$	280
Deferred tax liabilities:
Property and equipment	$	—		$	—
Texadian Energy intangibles		3,083
Prepaid insurance, marketable securities and other		32			280
Total deferred tax liabilities	$	3,115		$	280
Total deferred taxes, net	$	0		$	0

We have net operating loss carryovers as of December 31, 2012 of $1,286 million 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, 2012 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 until we have utilized our net operating loss carry over.

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Subsequent Events - Additional Information (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	1 Months Ended
	Mar. 25, 2013 Subsequent Event Issuance of Equity	Feb. 20, 2013 Subsequent Event Compressors	Dec. 31, 2012 Senior Secured Delayed Draw Term Loan	Jan. 17, 2013 Senior Secured Delayed Draw Term Loan Subsequent Event
Subsequent Event [Line Items]
Borrowed term loan			$ 13,465	$ 8,000
Proceeds from sale of drilling assets - assets held for sale		$ 2,800
Stock issued to settle bankruptcy claims	1,469,575

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Results of Operations for Oil and Gas Producing Activities, Excluding General and Administrative Cost (Detail) (USD $)	1 Months Ended	3 Months Ended	4 Months Ended			2 Months Ended	3 Months Ended						8 Months Ended	12 Months Ended	8 Months Ended	12 Months Ended
	Sep. 30, 2012 Successor	Dec. 31, 2012 Successor	Dec. 31, 2012 Successor	Dec. 31, 2012 Successor Company	Dec. 31, 2012 Successor Company's Share of Piceance Energy	Aug. 31, 2012 Predecessor	Jun. 30, 2012 Predecessor	Mar. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor	Sep. 30, 2011 Predecessor	Jun. 30, 2011 Predecessor	Mar. 31, 2011 Predecessor	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor	Aug. 31, 2012 Predecessor Company	Dec. 31, 2011 Predecessor Company
Revenue:
Oil and gas revenues	$ 584,000	$ 1,560,000	$ 2,144,000	$ 2,144,000	$ 6,464,000	$ 5,466,000	$ 7,703,000	$ 9,910,000	$ 12,737,000	$ 16,546,000	$ 16,882,000	$ 17,715,000	$ 23,079,000	$ 63,880,000	$ 23,079,000	$ 63,880,000
Expenses:
Production costs				1,688,000	3,033,000										16,980,000	29,157,000
Depletion and amortization			401,000	370,000	2,808,000								16,041,000	39,088,000	16,041,000	36,624,000
Exploration			0										2,000	338,000	2,000	338,000
Abandoned and impaired properties			0										151,347,000	420,402,000	151,347,000	419,851,000
Dry hole costs																355,000
Results of operations of oil and gas producing activities			709,000	86,000	623,000										(161,291,000)	(422,445,000)
Income (loss) from operations of properties sold, net																2,280,000
Gain on sale of properties			0										0	14,699,000		6,874,000
Income from results of discontinued operations of oil and gas producing activities			$ 0										$ 0	$ 14,094,000		$ 9,154,000

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Costs Incurred in Oil and Gas Activities (Parenthetical) (Detail) (USD $) In Thousands, unless otherwise specified	4 Months Ended
	Dec. 31, 2012
Predecessor
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved properties acquisition costs	$ 24,200
Laramie
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved properties acquisition costs	$ 8,300

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012	Mar. 25, 2013	Jun. 29, 2012
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Trading Symbol	PARR
Entity Registrant Name	PAR PETROLEUM CORP/CO
Entity Central Index Key	0000821483
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		150,080,405
Entity Public Float			$ 2,860,000

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Earnings Per Share

12 Months Ended

Dec. 31, 2012

Earnings Per Share

(12) Earnings Per Share

Basic earnings per share (“EPS”) are 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, representing 9,592,125 shares (see Note 6 and 7). U.S. GAAP requires the inclusion of these Warrants in the calculation of basic EPS because they are issuable for minimal consideration. The following table sets forth the computation of basic and diluted earnings per share (in thousands, except per share amounts):

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Net loss attributable to common stockholders	$	(8,839	)	$	(45,437	)	$	(484,134	)
Gain from discontinued operations, net of tax		0			—			14,023
Net loss attributable to common stockholders	$	(8,839	)	$	(45,437	)	$	(470,111	)
Basic weighted-average common stock outstanding		157,335			28,841			28,841
Add: dilutive effects of stock options and unvested stock grants		0			—			—
Diluted weighted-average common stock outstanding		157,335			28,841			28,841
Basic loss per common share attributable to common stockholders:
Loss from continuing operations	$	(0.06	)	$	(1.57	)	$	(16.79	)
Discontinued operations		0			—			0.49
Net loss	$	(0.06	)	$	(1.57	)	$	(16.30	)
Diluted loss per common share attributable to common stockholders:
Loss from continuing operations	$	(0.06	)	$	(1.57	)	$	(16.79	)
Discontinued operations		0			—			0.49
Net loss	$	(0.06	)	$	(1.57	)	$	(16.30	)

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

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012		Year Ended December 31, 2011
Stock issuable upon conversion of convertible notes		0		379		379
Stock options		0		150		150
Non-vested restricted stock		0		558		558
Total potentially dilutive securities		0		1,087		1,087

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United States Federal Income Tax Rate (Detail)	4 Months Ended		8 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 Successor	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor
Income Tax Rate Reconciliation [Line Items]
Federal statutory rate	35.00%	(35.00%)	(35.00%)	(35.00%)
State income taxes, net of federal benefit		0.00%	0.00%	(1.90%)
Change in valuation allowance		(2.00%)	(33.00%)	34.30%
Professional fees related to bankruptcy reorganization		8.00%	17.00%	1.80%
Revenue from Wapiti Trust settlement		5.00%	0.00%	0.00%
Cancellation of debt tax attribute reduction		0.00%	51.00%	0.00%
Actual income tax rate		(24.00%)	0.00%	(0.80%)

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Costs Incurred in Oil and Gas Activities (Detail) (USD $) In Thousands, unless otherwise specified	4 Months Ended			8 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor Company's Share of Piceance Energy		Dec. 31, 2012 Predecessor	Aug. 31, 2012 Predecessor Company	Dec. 31, 2011 Predecessor Company
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved properties acquisition costs	$ 206				$ 452
Proved properties acquisition costs	32,519	[1]	24,200		(51)
Development costs incurred on proved undeveloped reserves				1,613	4,858
Development costs-other	291				39,980
Exploration and dry hole costs					98
Total	$ 33,016			$ 1,613	$ 45,337

[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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Consolidated Statements of Operations (USD $)	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor
Revenue:
Oil and gas sales	$ 2,144,000	$ 23,079,000	$ 63,880,000
Operating Expenses:
Lease operating expense	1,684,000	9,038,000	13,755,000
Transportation expense	0	6,963,000	13,867,000
Production taxes	4,000	979,000	1,535,000
Exploration expense	0	2,000	338,000
Dry hole costs and impairments	0	151,347,000	420,402,000
Depreciation, depletion, amortization and accretion	401,000	16,041,000	39,088,000
General and administrative expense	5,076,000	9,386,000	28,124,000
Total operating expenses	7,165,000	193,756,000	517,109,000
Loss from unconsolidated affiliates	(1,325,000)	0	0
Operating income (loss)	(6,346,000)	(170,677,000)	(453,229,000)
Other income and (expense):
Interest expense and financing costs, net	(1,056,000)	(6,852,000)	(32,324,000)
Other income (expense)	86,000	516,000	(1,947,000)
Realized loss on derivative instruments, net	0	0	(3,368,000)
Unrealized (loss) gain on derivative instruments, net	(4,280,000)	0	2,993,000
Income (loss) from unconsolidated affiliates	0	(20,000)	344,000
Total other expense	(5,250,000)	(6,356,000)	(34,302,000)
Loss from continuing operations before income taxes, reorganization items and discontinued operations	(11,596,000)	(177,033,000)	(487,531,000)
Income tax expense (benefit)	(2,757,000)	0	(4,329,000)
Loss from continuing operations	(8,839,000)	(177,033,000)	(483,202,000)
Reorganization items
Professional fees and administrative costs	0	22,354,000	932,000
Changes in asset fair values due to fresh start accounting adjustments	0	14,765,000	0
Gain on settlement of senior debt	0	(166,144,000)	0
Gain on settlement of liabilities	0	(2,571,000)	0
Discontinued operations:
Gain from results of operations and sale of discontinued operations, net of tax	0	0	14,094,000
Net loss	(8,839,000)	(45,437,000)	(470,040,000)
Less net loss attributable to non-controlling interest included in discontinued operations	0	0	(71,000)
Net loss	(8,839,000)	(45,437,000)	(470,111,000)
Amounts attributable to common stockholders:
Loss from continuing operations	(8,839,000)	(45,437,000)	(484,134,000)
Gain from discontinued operations, net of tax	0	0	14,023,000
Net loss	$ (8,839,000)	$ (45,437,000)	$ (470,111,000)
Basic loss attributable to common stockholders per common share:
Loss from continuing operations	$ (0.06)	$ (1.57)	$ (16.79)
Discontinued operations	$ 0.00	$ 0.00	$ 0.49
Net loss	$ (0.06)	$ (1.57)	$ (16.30)
Diluted loss attributable to common stockholders per common share:
Loss from continuing operations	$ (0.06)	$ (1.57)	$ (16.79)
Discontinued operations	$ 0.00	$ 0.00	$ 0.49
Net loss	$ (0.06)	$ (1.57)	$ (16.30)

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Debt

12 Months Ended

Dec. 31, 2012

Debt

(6) Debt

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 $30.0 million. We borrowed $13.0 million on the Effective Date in order to, along with the proceeds from the Contribution Agreement, (i) repay the loans and obligations due under the DIP Credit Facility, and (ii) pay allowed but unpaid administrative expenses to the Debtors related to the Plan.

Below are certain of the material terms of the Loan Agreement:

Interest. At our election, any Loans will bear interest at a rate equal to 9.75% per annum payable either (i) in cash, quarterly, in arrears at the end of each calendar quarter or (ii) in-kind, accruing quarterly. In addition, all repayments due under the Loan Agreement will be charged a minimum of a 3% repayment premium. Accordingly, we will accrete amounts due for the minimum repayment premium over the term of loan using the effective interest method.

At any time after an event of default under the Loan Agreement has occurred and is continuing, (i) all outstanding obligations will, to the extent permitted by applicable law, bear interest at a rate per annum equal to 11.75% and (ii) all interest accrued and accruing will be payable in cash on demand.

Prepayment. We may prepay Loans at any time, in any amount. Such prepayment is to include all accrued and unpaid interest on the portion of the obligations being prepaid through the prepayment date. If at any time within the twelve months following the Emergence Date, we prepay the obligations due, in whole, but not in part, then in addition to the repayment of 100% of the principal amount of the obligations being prepaid plus accrued and unpaid interest thereon, we are required to pay the interest that would have accrued on the prepaid amount through the first anniversary of the Emergence Date plus a 6% prepayment premium.

In addition to the above described prepayment premium, we will pay a repayment premium equal to the percentage of the principal repaid during the following periods:

Period	Repayment Premium
From the Emergence Date through the first anniversary of the Emergence Date		6	%
From the day after the first anniversary of the Emergence Date through the second anniversary of the Emergence Date		5	%
At all times from and after the day after the second anniversary of the Emergence Date		3	%

We are also required to make certain mandatory repayments after certain dispositions of property, debt issuances, joint venture distributions from Piceance Energy, casualty events and equity issuances, in each case subject to customary reinvestment provisions. These mandatory repayments are subject to the prepayment premiums described above.

The contingent repayments described above are required to be accounted for as an embedded derivative. The estimated fair of the embedded derivative at issuance was approximately $65,000 and was recorded as a derivative liability with the offset to debt discount. Subsequent changes in fair value are reflected in earnings.

Collateral. The Loans and all obligations arising under the Loan Agreement are secured by (i) a perfected, first-priority security interest in all of our assets other than our equity interest in Piceance Energy held by Par Piceance Energy Equity, pursuant to a pledge and security agreement made by us and certain of our subsidiaries in favor of the Agent, and (ii) a perfected, second-lien security interest in our equity interest in Piceance Energy held by Par Piceance Energy Equity, pursuant to a pledge agreement by Par Piceance Energy Equity in favor of the Agent. The priority of the Lenders’ security interest in our assets is specified in that certain intercreditor agreement (the “Intercreditor Agreement”), among JPMorgan Chase Bank, N.A., as administrative agent for the First Priority Secured Parties (as defined in the Intercreditor Agreement), the Agent, as administrative agent for the Second Priority Secured Parties (as defined in the Intercreditor Agreement), the Company and Par Piceance Energy Equity.

Guaranty. All of our obligations under the Loan Agreement are unconditionally guaranteed by the Guarantors.

Fees and Commissions. We agreed to pay the Agent an annual nonrefundable administrative fee that was earned in full on the Effective Date. In addition, we agreed to pay the Lenders a nonrefundable closing fee that was earned in full on the Effective Date.

Warrants. As consideration for granting the Loans, we have also issued warrants to the Lenders to purchase shares of our common stock as described under “– Warrant Issuance Agreement” below.

Term. All loans and all other obligations outstanding under the Loan Agreement are payable in full on August 31, 2016.

Covenants. The Loan Agreement has no financial covenants that we are required to comply with; however, it does require us to comply with various affirmative and negative covenants affecting our business and operations which we were in compliance with at December 31, 2012.

Amendment to the Loan Agreement—Tranche B Loan

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 the Lenders agreed to extend additional borrowings to us (the “Tranche B Loan”). The total commitment of the Tranche B Loan of $35.0 million was drawn at closing. In addition to funding a portion of the purchase price of the acquisition of Texadian, the Tranche B Loan provides cash collateral for the Letter of Credit Facility with Compass Bank (as described below).

Set forth below are certain of the material terms of the Tranche B Loan:

Interest. At our election, the Tranche B Loan will bear interest at a rate equal to 9.75% per annum payable either (i) in cash or (ii) in-kind.

At any time after an event of default has occurred and is continuing, (i) all outstanding obligations will, to the extent permitted by applicable law, bear interest at a rate per annum equal to 11.75% and (ii) all interest accrued and accruing will be payable in cash on demand.

Prepayment. We may prepay the Tranche B Loan 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 entire outstanding principal amount of the Tranche B Loan.

Maturity date. The maturity date is July 1, 2013.

Collateral. The Tranche B Loan is secured by a lien on substantially all of our assets and our subsidiaries, including Texadian, but excluding our equity interests in Piceance Energy.

Guaranty. All of our obligations under the Tranche B Loan are unconditionally guaranteed by the Guarantors, including, Texadian.

Fees and Commissions. We agreed to pay the Lenders a nonrefundable exit fee equal to five percent (5%) of the aggregate amount of the Tranche B Loan. The exit fee is earned in full and payable on the maturity date of the Tranche B Loan or, if earlier, the date on which the Tranche B Loan is paid in full. Accordingly, we will accrete amounts due for the nonrefundable exit fee over the term of loan using the effective interest method.

Letter of Credit Facility

On December 27, 2012, we entered into a letter of credit facility agreement with Compass Bank, as the lender (the “Compass Letter of Credit Facility”). The Compass Letter of Credit Facility, which matures on December 26, 2013, provides for a letter of credit facility in an aggregate principal amount of $30.0 million that is available for the issuance of cash-collateralized standby letters of credit for us or any of our subsidiaries’ account. Letters of credit issued under the Compass Letter of Credit Facility are secured by an amount of cash pledged and delivered by us to Compass equal to one hundred five percent (105%) of the undrawn amount of all outstanding letters of credit. We agreed to pay a letter of credit fee equal to one and one half percent (1.5%) per annum of the stated face amount of each letter of credit for the number of days such letter of credit is to remain outstanding plus standard and customary administrative fees. The Compass Letter of Credit Facility does not contain any financial covenants; however, it does require us to comply with various affirmative and negative covenants affecting our business and operations, which we are in compliance with at December 31, 2012.

In connection with the acquisition of Texadian, Compass Bank issued an Irrevocable Standby Letter of Credit in favor of SEACOR Holdings in the amount of $11.71 million (the “Irrevocable Standby Letter of Credit”). The Irrevocable Standby Letter of Credit will secure SEACOR Holdings in the event that either of the following letters of credit is drawn: (i) the letter of credit issued by DNB Bank, ASA in favor of Suncor Energy Marketing Inc., with an original maturity date of February 5, 2013; or (ii) the letter of credit issued by DNB Bank, ASA in favor of Cenovus Energy Marketing Services Limited, with an original maturity date of February 5, 2013. These letters of credit have been terminated and released.

Cross Default Provisions

Included within each of the Company’s 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.

Warrant Issuance Agreement

Pursuant to the Plan, on the Effective Date, we issued to the Lenders warrants (the “Warrants”) to purchase up to an aggregate of 9,592,125 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 Effective 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 $0.01 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 Warrant Shares issued on the Effective Date was determined based on the number of shares of our common stock issued as allowed claims on or about the Effective Date by the Bankruptcy Court pursuant to the Plan. The Warrant Issuance Agreement provides that the number of Warrant Shares and the Exercise Price shall be adjusted in the event that any additional shares of common stock or securities convertible into common stock (the “Unresolved Bankruptcy Shares”) are authorized to be issued under the Plan by the Bankruptcy Court after the Effective Date as a result of any unresolved bankruptcy claims under the Plan. Upon each issuance of any Unresolved Bankruptcy Shares, the Exercise Price shall be reduced to an amount equal to the product obtained by multiplying (A) the Exercise Price in effect immediately prior to such issuance or sale, by (B) a fraction, the numerator of which shall be (x) 147,655,815 and (y) the denominator of which shall be the sum of (1) 147,655,815 and (2) and the number of additional Unresolved Bankruptcy Shares authorized for issuance under the Plan. Upon each such adjustment of the Exercise Price, the number of Warrant Shares shall be increased to the number of shares determined by multiplying (A) the number of Warrant Shares which could be obtained upon exercise of such Warrant immediately prior to such adjustment by (B) a fraction, the numerator of which shall be the Exercise Price in effect immediately prior to such adjustment and the denominator of which shall be the Exercise Price in effect immediately after such adjustment. In the event that any Lender or its affiliates fails to fund its pro rata portion of any Loans required to be made under the Loan Agreement, then the number of Warrant Shares exercisable under the Warrants held by such Lender will be reduced to an amount equal to the product of (i) the number of Warrant Shares initially exercisable under the Warrant held by the Lender and (ii) a fraction equal to one minus the quotient obtained by dividing (x) the amount of Loans previously made under the Loan Agreement by such Lender by (y) such Lender’s full commitment for Loans.

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.

Based on certain anti-dilution provisions in the Warrant Issuance Agreement, we have concluded that the Warrants are not indexed to our equity. Accordingly, we have 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 will be amortized over the life of the Loan Agreement, using the effective interest method. Subsequent changes in the fair value of the Warrants will be reflected in earnings.

Summary

Our debt at December 31, 2012 is as follows (in thousands):

Tranche B Loan	$	35,000
Delayed Draw Term Loan Agreement		13,465
Less: unamortized debt discount – warrants		(6,014	)
Less: unamortized debt discount – embedded derivative		(60	)
Total debt, net of unamortized debt discount		42,391
Less: current maturities		(35,000	)
Long term debt, net of current maturities and unamortized discount	$	7,391

For the period from September 1 through December 31, 2012, interest expense totaled approximately $1,056,000 consisting of approximately $432,000 of interest accrued in kind and approximately $33,000 of accretion related to the 3% repayment premium both of which are related to the Loan Agreement and approximately $592,000 related to amortization of the debt discount originating from the warrants and embedded derivative. We have made no cash interest payments during the period from September 1, 2012 to December 31, 2012.

Debtor in Possession Credit Agreement

On December 21, 2011, Predecessor entered into a senior secured debtor-in-possession credit facility (the “DIP Credit Facility”) in connection with the bankruptcy filing. Up to $57.5 million could be borrowed under the DIP Credit Facility, of which approximately $45 million was initially drawn by Predecessor to repay all amounts outstanding under the previous credit agreement, which was then terminated. The DIP Credit Facility was amended in March 2012 to increase the maximum borrowing capacity by $1.4 million to $58.9 million. All of the loans under the DIP Credit Facility were term loans. The interest rate under the DIP Credit Facility was 13% plus 6% per annum in payment-in-kind interest. The initial maturity date of the DIP Credit Facility was June 30, 2012. Predecessor subsequently entered into a series of forbearance agreements extending the maturity date to August 31, 2012. The DIP Credit Facility was repaid in full and terminated in accordance with the Plan.

7% Senior Unsecured Notes, due 2015

On March 15, 2005, Predecessor issued 7% senior unsecured notes due 2015 for an aggregate principal amount of $150.0 million. The bankruptcy filing constituted an event of default on the notes resulting in all principal, interest and other amounts due relating to the notes becoming immediately due and payable. The notes were settled in accordance with the Plan.

3 ³/₄% Senior Convertible Notes, due 2037

On April 25, 2007, Predecessor issued $115.0 million aggregate principal amount of 3 ³/₄% Senior Convertible Notes due 2037 for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The bankruptcy filing constituted an event of default on the notes resulting in all principal, interest and other amounts due relating to the notes becoming immediately due and payable. The notes were settled in accordance with the Plan.

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Acquisition

12 Months Ended

Dec. 31, 2012

Acquisition

(5) Acquisition

On December 31, 2012, we acquired Texadian Energy, Inc. (formerly known as SEACOR Energy, Inc. (“Texadian”), an indirect wholly-owned subsidiary of SEACOR Holdings Inc., for $14.0 million plus estimated net working capital of approximately $4.0 million at closing resulting in approximately $18.0 million of cash paid at closing. Texadian operates a crude oil marketing, transportation, distribution and marketing business with significant logistics capabilities. We acquired Texadian in furtherance of our growth strategy that focuses on the acquisition of income producing businesses. The purchase price for the acquisition was funded with a combination of cash and additional borrowings under an amendment to our existing delayed draw term loan facility referred to as the Tranche B Loan (see Note 6).

The purchase was accounted for as a purchase business combination in accordance with ASC 805 whereby the purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values on the date of acquisition (see Note 7). Goodwill is defined in ASC 805 as the future economic benefit of other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is attributable to the synergies 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		7,756
Net non cash working capital		3,631
Deferred tax liabilities		(2,757	)
Total, net of cash acquired	$	17,439

The intangible assets will be amortized over their estimated useful lives on a straight line basis. The weighted average useful life is 7.3 years. Estimated amortization expense is expected to be as follows (in thousands):

Year Ended
2013	$	2,008
2014		2,008
2015		908
2016		908
2017		908
Thereafter		2,069
	$	8,809

None of the goodwill or intangible assets are expected to be deductible for income tax reporting purposes.

The results of operations of Texadian will be included in our consolidated statement of operations beginning January 1, 2013. Texadian’s revenues for the year ended December 31, 2012 were approximately $515.5 million (unaudited), and its net income was approximately $2.3 million (unaudited), of which approximately $122.9 (unaudited) million revenue and net income of approximately $800,000 (unaudited) is attributable to the period from September 1, 2012 through December 31, 2012. Texadian’s revenues for the year ended December 31, 2011 was approximately $731 million (unaudited), and its net loss was approximately $(748,000) (unaudited). Accordingly, had the acquisition occurred as of September 1, 2012, our consolidated revenue and net loss would have been approximately $125.0 million (unaudited) and $8.6 million (unaudited), respectively, including amortization of the acquired intangibles. We have not presented pro forma results for Predecessor periods as the entities are not comparable. Acquisition costs totaled approximately $556,000 are included in general and administrative expenses in our consolidated statement of operations.

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Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Data (Unaudited)

(17) Selected Quarterly Financial Data (Unaudited)

	Predecessor									Successor
	Quarter Ended						Period from July 1 through August 31			Month Ended September 30,			Quarter Ended December 31,
(in thousands)	March 31,			June 30,
Year Ended December 31, 2012
Total revenue	$	9,910		$	7,703		$	5,466		$	584		$	1,560
Loss from continuing operations		(8,121	)		(10,003	)		(158,910	)		(2,002	)		(6,837	)
Reorganization Items(1)		5,342			5,910			(142,848	)		—			—
Net loss		(13,463	)		(15,913	)		(16,062	)		(2,002	)		(6,837	)
Net income (loss) per common share:(1)
Basic	$	(0.46	)	$	(0.55	)	$	(0.56	)	$	(0.01	)	$	(0.05	)
Diluted	$	(0.46	)	$	(0.55	)	$	(0.56	)	$	(0.01	)	$	(0.05	)
Total Assets(2)	$	374,527		$	364,752		$	142,911		$	138,447		$	189,582
Total Equity(2)	$	37,779		$	22,745		$	109,562		$	107,560		$	100,757
Cash Flow from Operations(1)	$	(3,641	)	$	(9,513	)	$	(7,108	)	$	(347	)	$	(4,289	)
Cash Flow from Investing(1)	$	(679	)	$	327		$	72,974		$	—			(17,690	)
Cash Flow from Financing(1)	$	—		$	5,000		$	(65,340	)	$	2,000			21,629

(1) In preparing the December 31, 2012 financial statements, we recorded an immaterial correction of an error pursuant to FASB ASC Topic 250, Accounting Changes and Error Corrections. The error related to the presentation of the gain on settlement of liabilities and fresh start accounting through the statement of equity as of September 1, 2012. As a result of application of the provisions of FASB ASC Topic 852, Reorganizations, the effect of the reorganization should have been reflected in the statement of operations of the Predecessor for the period from July 1 through August 31, 2012. The effect of the reorganization was previously disclosed in the footnotes to the Form 10-Q for the period ended September 30, 2012 and the Company believes the correction of this error is not material to its previously issued Predecessor financial statements. The Company has adjusted certain balances within the statement of operations and cash flows to correct this presentation error as follows:

	Predecessor
	Period from July 1, 2012 Through August 31, 2012
	As reported			Adjustments			As Corrected
	(in thousands)
Statement of Operations
Loss from continuing operations before income taxes, reorganization items and discontinued operations	$	(158,910	)	$	—		$	(158,910	)
Reorganization items
Professional fees and administrative costs		(10,719	)		—			(10,719	)
Gain on settlement of liabilities		—			168,332			168,332
Fresh Start Adjustments		—			(14,765	)		(14,765	)
Net loss	$	(169,629	)	$	153,567		$	(16,062	)
Cash Flow Data
Cash flow used in operations	$	(4,709	)	$	(2,399	)	$	(7,108	)
Cash flow provided by investing activities		(1,193	)		74,167			72,974
Cash flow used in financing activities		3,500			(68,840	)		(65,340	)

(2) Reflects true-up adjustments to the preliminary fresh start accounting values recorded at September 30, 2012.

	Predecessor
	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share amounts)
Year Ended December 31, 2011 (Predecessor)
Total revenue	$	17,715		$	16,882		$	16,546		$	12,737
Loss from continuing operations before income taxes, discontinued operations and cumulative effect		(27,424	)		(12,724	)		(429,973	)		(17,411	)
Net loss		(27,841	)		(963	)		(429,430	)		(11,877	)
Net income (loss) per common share:(1)
Basic	$	(1.00	)	$	(0.03	)	$	(15.40	)	$	(0.43	)
Diluted	$	(1.00	)	$	(0.03	)	$	(15.40	)	$	(0.43	)

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Predecessor Employee Benefits

12 Months Ended

Dec. 31, 2012

Predecessor Employee Benefits

(13) Predecessor Employee Benefits

The Predecessor adopted a profit sharing plan on January 1, 2002. All employees were eligible to participate and contributions to the profit sharing plan were voluntary and must be approved by the Board of Directors. Amounts contributed to the Plan vested over a six year service period.

The Predecessor adopted a 401(k) plan effective May 1, 2005. All employees are eligible to participate and make employee contributions once they have met the plan’s eligibility criteria. Under the 401(k) plan, the Predecessor’s employees make salary reduction contributions in accordance with the Internal Revenue Service guidelines. The Predecessor’s matching contribution was an amount equal to 100% of the employee’s elective deferral contribution which cannot exceed 3% of the employee’s compensation, and 50% of the employee’s elective deferral which exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’s compensation. The expense recognized in relation to the 401(k) plan was $176,000 for 2011. The 401(k) matching contribution was suspended in April 2009, but was subsequently reinstated January 1, 2010.

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Potentially Dilutive Securities Excluded from Calculation of Diluted Shares Outstanding (Detail) In Thousands, unless otherwise specified	4 Months Ended				8 Months Ended	12 Months Ended	8 Months Ended	12 Months Ended	8 Months Ended	12 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor	Dec. 31, 2012 Successor Stock Issuable upon Conversion of Convertible Notes	Dec. 31, 2012 Successor Stock Options and Warrants	Dec. 31, 2012 Successor Non-Vested Restricted Stock	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor	Aug. 31, 2012 Predecessor Stock Issuable upon Conversion of Convertible Notes	Dec. 31, 2011 Predecessor Stock Issuable upon Conversion of Convertible Notes	Aug. 31, 2012 Predecessor Stock Options and Warrants	Dec. 31, 2011 Predecessor Stock Options and Warrants	Aug. 31, 2012 Predecessor Non-Vested Restricted Stock	Dec. 31, 2011 Predecessor Non-Vested Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Total potentially dilutive securities	0	0	0	0	1,087	1,087	379	379	150	150	558	558

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies

(9) Commitments and Contingencies

Recovery Trusts

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, 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 $1.0 million each pursuant to the Plan.

On September 19, 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. Further distributions are not anticipated from the Wapiti Trust and the Wapiti Trust is anticipated to be 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 Executive Officer is the 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 for each of the Recovery Trusts, subject to the terms of the respective trust agreements 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 March 19, 2013, the Recovery Trusts have released approximately $5.2 million to us, which is available for our general use, resulting from the distribution agent resulting from excess proceeds after a negotiated reduction in certain fees and claims associated with the bankruptcy, as well as a favorable variance in actual expenses incurred compared to 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, 106 claims totaling approximately $73.7 million had been filed in the bankruptcy. Between the Emergence Date and December 31, 2012, the Recovery Trustee settled 25 claims with an aggregate face amount of approximately $6.6 million for $258,905 in cash and 202,753 shares of stock. Subsequent to year end and up to March 19, 2013, the Recovery Trustee settled an additional 25 claims with an aggregate face amount of approximately $12.3 million for $676,092 in cash and 1,469,575 shares of stock.

As of March 19, 2013, it is estimated that a total of 56 claims totaling approximately $54.8 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. Par believes 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. In addition, litigation and/or settlement efforts are ongoing with Macquarie Capital (USA) Inc., Swann and Buzzard Creek Royalty Trust, as well as other claim holders.

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 544 shares per $1,000 of claim. At December 31, 2012, we have reserved approximately $8.7 million representing the estimated value of claims remaining to be settled which are deemed probable and estimable at year end. A summary of claims is as follows:

	Emergence-Date August 31, 2012				Year-ended December 31, 2012
	Filed Claims				Settled Claims								Remaining Filed Claims
									Consideration
	Count		Amount		Count		Amount		Cash		Stock		Count		Amount
U.S. Government Claims		3	$	22,364,000		—	$	—	$	—		—		3	$	22,364,000
Former Employee Claims		32		16,379,849		13		3,685,253		229,478		202,231		19		12,694,596
Macquarie Capital (USA) Inc.		1		8,671,865		—		—		—		—		1		8,671,865
Swann and Buzzard Creek Royalty Trust		1		3,200,000		—		—		—		—		1		3,200,000
Other Various Claims*		69		23,120,396		12		2,914,859		29,427		522		57		20,205,537
Total		106	$	73,736,110		25	$	6,600,112	$	258,905		202,753		81	$	67,135,998

	Subsequent to Year-ended December 31, 2012 through March 19, 2013
	Settled Claims								Remaining Filed Claims
					Consideration
	Count		Amount		Cash		Stock		Count		Amount
U.S. Government Claims		—	$	—	$	—		—		3	$	22,364,000
Former Employee Claims		12		11,750,904		278,338		1,361,452		7		943,692
Macquarie Capital (USA) Inc.		—		—		—		—		1		8,671,865
Swann and Buzzard Creek Royalty Trust		—		—		—		—		1		3,200,000
Other Various Claims*		13		581,607		397,754		108,123		44		19,623,930
Total		25	$	12,332,511	$	676,092		1,469,575		56	$	54,803,487

* Includes reserve for contingent/unliquidated claims in the amount of $10 million

Texadian Leases

As of December 31, 2012, Texadian had 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.

Texadian’s railcar leases contain an empty mileage indemnification provision whereby if the empty mileage exceeds the loaded mileage, Texadian is charged for the empty mileage at the rate established by the tariff of the railroad on which the empty miles accrued.

Future minimum payments under operating leases that have a remaining term in excess of one year as of December 31, 2012 were as follows (in thousands):

2013	$	1,496
2014		1,496
2015		1,496
2016		1,496
2017		660
	$	6,644

Employee Matters

The Predecessor had, as of December 31, 2011, agreements with its three executive officers which provide for severance payments equal to three times the average of the officer’s combined annual salary and bonus, benefits continuation and accelerated vesting of options and stock grants in the event that there is a change in control of the Company. These agreements were amended on December 29, 2010 to bring them into compliance with Section 409A of the Code. These executory agreements were neither assumed nor rejected in Delta’s chapter 11 case, though two of them became nonexecutory upon the termination of the executives in question.

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Fair Value of Assets and Liabilities Assumed (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Total, net of cash acquired	$ 17,439
Net non-cash working capital
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Purchase price allocation, assets acquired	3,631	[1]
Supplier Relationships
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Purchase price allocation, assets acquired	3,360	[2]
Historical Shipper Status
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Purchase price allocation, assets acquired	2,200	[3]
Rail Car leases
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Purchase price allocation, assets acquired	3,249	[4]
Goodwill
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Purchase price allocation, assets acquired	7,756	[5]
Deferred Tax Liability
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Purchase price allocation, liabilities assumed	$ (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 shippers, 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.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Measurements

(7) Fair Value Measurements

We follow accounting guidance which defines fair value, establishes a framework for measuring fair value in U.S. GAAP, and requires additional disclosures about fair value measurements. As required, we applied the following fair value hierarchy:

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 transfer 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. These valuation policies are determined by our Chief Financial Officer and approved by our Chief Executive Officer. They are discussed with our Audit Committee as deemed appropriate. Each quarter, our Chief Financial Officer and Chief Executive Officer update the inputs used in the fair value measurement and internally review the changes from period to period for reasonableness. 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 Accounting – The fair value of the Successor was based on its estimated enterprise value post-bankruptcy using valuation techniques described in notes (a) through (f) described 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 have been reflected in the Successor’s consolidated balance sheet as of August 31, 2012.

	Fair Value at August 31, 2012		Fair Value Technique
	(in thousands)
Oil and gas properties
Proved	$	4,587		(a	)(b)
Other assets
Frac tanks	$	1,400		(c	)
Compressors		2,800		(d	)
Miscellaneous		39		(e	)
	$	4,239
Investment in Piceance Energy	$	105,344		(f	)

(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 was valued using a market valuation technique which was based on published listings of similar equipment. We consider this to be a level 2 fair value measurement.

(d) The estimated fair value of the compressor units was valued using a market valuation technique based on standalone bids received by third-parties. We consider this to be a level 2 fair value measurement.

(e) 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.

(f) The estimated fair value of our investment in Piceance Energy is 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. A change in significant inputs such a reduction in commodity pricing or an increase in discount rates would result in a lower fair value.

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 (e) described below.

	Fair Value at December 31, 2012			Fair Value 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 shippers, 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.

Proved property impairments – The fair values of the proved properties are estimated using internal discounted cash flow calculations based upon our estimates of reserves and are considered to be level 3 fair value measurements. This estimation is based on an independent reserve report with industry standard discounts applied to the reserves.

Asset retirement obligations – The initial fair values of the asset retirement obligations are estimated using the income valuation technique and internal discounted cash flow calculations based upon the our asset retirement obligations, including revisions of the estimated fair values during the period from September 1 through December 31, 2012, and are considered to be level 3 fair value measurements.

Assets and Liabilities Measure at Fair Value on a Recurring Basis

Derivative liabilities associated with our debt agreement – Derivative liabilities include the Warrants and fair value is estimated using an income valuation technique and 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 the initial stock price of $0.70 per share, initial exercise price $0.01, term of 10 years, risk free rate of 1.7%, and expected volatility of 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 $0.69 per share at issuance or $6.6 million. 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. There was no material change in the inputs used to measure fair value or in the fair value as of December 31, 2012.

In addition, our Loan Agreement contains 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 consider 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 of approximately $65,000 at issuance 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. There was no material change in the inputs used to measure fair value or in the fair value as of December 31, 2012.

Derivative instruments – With the acquisition of Texadian, we assumed certain open positions consisting of non-exchange traded fixed price physical contracts and exchange traded commodity swap, options and futures contracts. 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 and from third party broker quotes and pricing providers.

Our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 consist of the following (in thousands):

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

	Location on Consolidated Balance Sheet		Fair Value at December 31, 2012
			(in thousands)
Commodities – physical forward contracts		Prepaid and other current assets	$	(307	)
Commodities – exchange traded futures		Prepaid and other current assets	$	542
Warrant derivatives		Noncurrent liabilities	$	(10,900	)
Embedded derivative		Noncurrent liabilities	$	(45	)

A rollforward of Level 3 derivative warrants and the embedded derivative measured at fair value using level 3 on a recurring basis is as follows (in thousands):

Description
Balance, at September 1, 2012	$	(6,665	)
Purchases, issuances, and settlements		—
Total unrealized losses included in earnings		(4,280	)
Transfers		—
Balance, at December 31, 2012	$	(10,945	)

The estimated fair value and notional amounts of our open physical forward commodity contracts are shown in the table below (in thousands except volumes):

	Open Physical Forward Contracts
	December 31, 2012
				Notional Amounts
	Fair Value			Value		Volumes		Volume Unit		Maturity Dates
Crude oil	$	(227	)	WTI plus $	3.00		60,000		barrels		January 2013
Crude oil	$	(80	)	WTI plus $	15.00		21,497		barrels		January 2013

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Discontinued Operations

12 Months Ended

Dec. 31, 2012

Discontinued Operations

(8) Discontinued Operations

During the second quarter of 2011, Predecessor sold the remaining portion of our interests in non-core assets primarily located in Texas and Wyoming to Wapiti Oil and Gas, LLC (“Wapiti Oil and Gas”) (the “Wapiti Transaction”) for gross cash proceeds of approximately $43.2 million. On October 31, 2011, Predecessor sold its stock, representing a 49.8% ownership interest in DHS, to DHS’s lender for $500,000. In accordance with U.S. GAAP, the results of operations relating to these properties and DHS have been reflected as discontinued operations for all periods presented.

We had no activity from discontinued operations for the periods from September 1 through December 31, 2012 or from January 1 through August 31, 2012. The following table shows the oil and gas segment and drilling segment revenues and expenses included in discontinued operations as described above ended December 31, 2011 (in thousands):

	Predecessor Year Ended December 31, 2011
	Oil and Gas			Drilling			Total
Revenues:
Oil and gas sales	$	10,276		$	—		$	10,276
Contract drilling and trucking fees		—			45,241			45,241
Total Revenues		10,276			45,241			55,517
Operating Expenses:
Lease operating expense		2,482			—			2,482
Transportation expense		16			—			16
Production taxes		370			—			370
Dry hole costs and impairments(1)		608			—			608
Depreciation, depletion, amortization and accretion – oil and gas		2,796			—			2,796
Drilling and trucking operating expenses		—			35,617			35,617
Depreciation and amortization – drilling and trucking(2)		—			2,669			2,669
General and administrative expense		—			3,014			3,014
Total operating expenses		6,272			41,300			47,572
Operating income		4,004			3,941			7,945
Other income and (expense):
Interest expense and financing costs, net		—			(6,911	)		(6,911	)
Other income		—			2,734			2,734
Total other expense		—			(4,177	)		(4,177	)
Income (loss) from discontinued operations		4,004			(236	)		3,768
Income tax expense(3)		(1,724	)		—			(1,724	)
Income (loss) from results of operations of discontinued operations, net of tax		2,280			(236	)		2,044
Gain on sales of discontinued operations, net of tax(4)		6,874			5,176			12,050
Income from results of operations and sale of discontinued operations, net of tax	$	9,154		$	4,940		$	14,094

⁽¹⁾ Dry Hole Costs and Impairments. In 2011, we recorded impairments on our Columbia River, Greentown and Gulf Coast properties of $491,000 prior to their sale. In accordance with accounting standards, the impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction with the Wapiti Transaction were reflected as discontinued operations.

⁽²⁾ Depreciation and Amortization – Drilling and Trucking. Depreciation and amortization– drilling and trucking was $2.7 million for the year ended December 31, 2011. We stopped recording depreciation expense beginning in March 2011 in accordance with accounting rules related to the asset held for sale treatment of DHS.

⁽³⁾ Income tax expense. For the year ended December 31, 2011, we recorded a tax benefit of approximately $1.2 million due to a non-cash income tax benefit related to gains from discontinued oil and gas operations. U.S. GAAP requires all items be considered, including items recorded in discontinued operations, in determining the amount of tax benefit that results from a loss from continuing operations that should be allocated to continuing operations. In accordance with U.S. GAAP, we recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations.

⁽⁴⁾ Gain on sales of discontinued operations – oil and gas. In accordance with U.S. GAAP, we recognized a $5.6 million gain on sale ($8.9 million gain, net of $3.3 million of tax) for the year ended December 31, 2011 that is reflected in discontinued operations. In June 2011, DHS sold certain of its trucking assets for $3.3 million in proceeds and a gain of $2.9 million.

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Stockholders' Equity

12 Months Ended

Dec. 31, 2012

Stockholders' Equity

(10) Stockholders’ Equity

Pursuant to the Plan, on the Effective 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 145,736,082 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 1,919,733 shares of our common stock, and (iii) the Lenders under the Loan Agreement received warrants to purchase up to an aggregate of 9,592,125 shares of our common stock (which number of shares may be increased to an aggregate of 12,200,000 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 Effective 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.

Registration Rights Agreement

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 sixty (60) days after the Effective Date, any Stockholder or group of Stockholders that, together with its or their affiliates, holds more than fifteen percent (15%) 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 ninety (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 ninety (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.

Preferred Stock

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

Common Stock

On July 12, 2011, the stockholders of Predecessor approved a one-for-ten reverse split of its common stock which became effective on July 13, 2011. All references in the Predecessor financial statements to the number of shares of common stock or options, 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.

On December 31, 2012, a total of 30,524 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 $33,000 relating to these shares, which represents 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 $1.00 to $1.20 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.

Incentive Plan

On December 20, 2012, our Board of Directors 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 16 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.

On December 31, 2012, a total of 2,191,834 shares of our restricted common stock were granted to members of our Board of Directors and certain key employees. Restricted stock granted to members of our Board of Directors vests in full after one year from the date of grant, while restricted stock granted to employees vests on a pro-rata basis over five years. For the period from September 1, 2012 through December 31, 2012, the following activity occurred under our Incentive Plan:

	Shares		Weighted-Average Grant Date Fair Value
Stock Awards
Non vested balance, beginning of period		—		—
Granted		2,191,834	$	1.09
Vested		—		—
Forfeited		—		—
Non vested balance, end of period		2,191,834	$	1.09

As of December 31, 2012, there are approximately $2.4 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 4.8 years. The grant date fair value was estimated using the previous 20 days average trading price of our common stock.

In December 2012, we approved a new compensation plan for our directors. Our directors receive an annual retainer of $50,000, 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 $15,000 and the members of the Audit Committee (other than the Chairman) receive an annual retainer of $5,000, 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 $75,000, with the number of shares determined by the 60-day volume weighted average share price as of the day prior to the grant date.

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 statements of operations.

Predecessor recognized stock compensation expense of approximately $1.9 million and $8.0 million for the period from January 1, 2012 through August 31, 2012 and for the year ended December 31, 2011, respectively, which are included in general and administrative expenses. Under the terms of the Plan, 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 and for the year ended December 31, 2011 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		0		$	0			0		0
Exercisable-end of year		0		$	0			0		0

	Year Ended December 31, 2011
	Options			Weighted-Average Exercise Price			Weighted-Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding-beginning of year		160,800		$	72.60
Granted		—			—
Exercised		—			—
Expired		(10,500	)		(38.96	)
Outstanding-end of year		150,300		$	75.00			2.64 years		—
Exercisable-end of year		150,300		$	75.00			2.64 years		—

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 and for the year ended December 31, 2011 follows (in thousands accept 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		0			0
Vested		0			0
Expired / canceled		(558,301	)		(7.45	)
Nonvested-end of year		0		$	0			0	$	0

	Year Ended December 31, 2011
	Nonvested Stock			Weighted-Average Grant-Date Fair Value			Weighted-Average Remaining Contractual Term		Aggregate Intrinsic Value
Nonvested-beginning of year		734,376		$	15.27
Granted		598,836			5.92
Vested		(719,350	)		(11.74	)
Expired / Forfeited		(55,561	)		(36.22	)
Nonvested-end of year		558,301		$	7.45			0.48 years	$	3,307

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Rollforward of Level Three Derivative Warrants and Embedded Derivative Measured at Fair Value on Recurring Basis (Detail) (USD $) In Thousands, unless otherwise specified	4 Months Ended
	Dec. 31, 2012
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance, at September 1, 2012	$ (6,665)
Purchases, issuances, and settlements
Total unrealized losses included in earnings	(4,280)
Transfers
Balance, at December 31, 2012	$ (10,945)

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Predecessor Employee Benefits - Additional Information (Detail) (Predecessor, USD $)	8 Months Ended	12 Months Ended
	Aug. 31, 2012	Dec. 31, 2011
Predecessor
Defined Benefit Plan Disclosure [Line Items]
Profit sharing plan vesting period	6 years
Matching Contribution elective deferral		100.00%
Matching Contribution maximum employee salary		3.00%
Matching Contribution elective deferral above 3%		50.00%
Matching Contribution maximum employee salary above 3%		5.00%
Matching contribution Expense		$ 176,000

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Estimated Fair Value and Notional Amounts of Physical Forward Commodity Contracts (Parenthetical) (Detail) (Crude Oil, Physical Forward Contracts, USD $)	Dec. 31, 2012
Product 1
Fair Value of Derivative Instruments [Line Items]
Amount in addition to WTI	$ 3.00
Product 2
Fair Value of Derivative Instruments [Line Items]
Amount in addition to WTI	$ 15.00

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Selected Quarterly Financial Data (Parenthetical) (Detail) (Predecessor, USD $)	2 Months Ended		3 Months Ended												8 Months Ended	12 Months Ended
	Aug. 31, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Aug. 31, 2012	Dec. 31, 2011
Quarterly Financial Data [Line Items]
Total revenue	$ 5,466,000		$ 7,703,000		$ 9,910,000		$ 12,737,000		$ 16,546,000		$ 16,882,000		$ 17,715,000		$ 23,079,000	$ 63,880,000
Loss from continuing operations before income taxes, discontinued operations and cumulative effect	(158,910,000)		(10,003,000)		(8,121,000)		(17,411,000)		(429,973,000)		(12,724,000)		(27,424,000)		(177,033,000)	(487,531,000)
Reorganization items
Professional fees and administrative costs															(22,354,000)	(932,000)
Gain on settlement of liabilities															2,571,000	0
Fresh Start Adjustments															(14,765,000)	0
Net loss	(16,062,000)		(15,913,000)		(13,463,000)		(11,877,000)		(429,430,000)		(963,000)		(27,841,000)		(45,437,000)	(470,111,000)
Cash flow used in operations	(7,108,000)	[1]	(9,513,000)	[1]	(3,641,000)	[1]									(20,262,000)	990,000
Net income (loss) per common share:
Basic	$ (0.56)	[1]	$ (0.55)	[1]	$ (0.46)	[1]	$ (0.43)	[1]	$ (15.40)	[1]	$ (0.03)	[1]	$ (1.00)	[1]	$ (1.57)	$ (16.30)
Diluted	$ (0.56)	[1]	$ (0.55)	[1]	$ (0.46)	[1]	$ (0.43)	[1]	$ (15.40)	[1]	$ (0.03)	[1]	$ (1.00)	[1]	$ (1.57)	$ (16.30)
Cash flow provided by investing activities	72,974,000	[1]	327,000	[1]	(679,000)	[1]									72,622,000	87,649,000
Cash flow used in financing activities	(65,340,000)	[1]	5,000,000	[1]	0	[1]									(60,340,000)	(89,967,000)
Scenario, Previously Reported
Quarterly Financial Data [Line Items]
Loss from continuing operations before income taxes, discontinued operations and cumulative effect	(158,910,000)
Reorganization items
Professional fees and administrative costs	(10,719,000)
Net loss	(169,629,000)
Cash flow used in operations	(4,709,000)
Net income (loss) per common share:
Cash flow provided by investing activities	(1,193,000)
Cash flow used in financing activities	3,500,000
Scenario, Adjustment
Reorganization items
Gain on settlement of liabilities	168,332,000
Fresh Start Adjustments	(14,765,000)
Net loss	153,567,000
Cash flow used in operations	(2,399,000)
Net income (loss) per common share:
Cash flow provided by investing activities	74,167,000
Cash flow used in financing activities	68,840,000
Scenario, Actual
Quarterly Financial Data [Line Items]
Loss from continuing operations before income taxes, discontinued operations and cumulative effect	(158,910,000)
Reorganization items
Professional fees and administrative costs	(10,719,000)
Gain on settlement of liabilities	168,332,000
Fresh Start Adjustments	(14,765,000)
Net loss	(16,062,000)
Cash flow used in operations	(7,108,000)
Net income (loss) per common share:
Cash flow provided by investing activities	72,974,000
Cash flow used in financing activities	$ (65,340,000)

[1] In preparing the December 31, 2012 financial statements, we recorded an immaterial correction of an error pursuant to FASB ASC Topic 250, Accounting Changes and Error Corrections. The errors related to the presentation of the gain on settlement of liabilities and fresh start accounting through the statement of equity as of September 1, 2012. As a result of application of the provisions of FASB ASC Topic 852, Reorganizations, the effect of the reorganization should have been reflected in the statement of operations of the Predecessor for the period from July 1 through August 31, 2012. The effect of the reorganization was previously disclosed in the footnotes to the Form 10-Q for the period ended September 30, 2012 and the Company believes the correction of this error is not material to its previously issued Predecessor financial statements. The Company has adjusted certain balances within the statement of operations and cash flows to correct this presentation error as follows: Predecessor Period from July 1, 2012 Through August 31, 2012 As reported Adjustments As Corrected (in thousands) Statement of Operations Loss from continuing operations before income taxes, reorganization items and discontinued operations $ (158,910 ) - $ (158,910 ) Reorganization items Professional fees and administrative costs (10,719 ) - (10,719 ) Gain on settlement of liabilities 168,332 168,332 Fresh Start Adjustments (14,765 ) (14,765 ) Net loss $ (169,629 ) $ 156,767 $ (16,062 ) Cash Flow Data Cash flow used in operations $ (17,863 ) $ (2,399 ) $ (20,262 ) Cash flow provided by investing activities (1,545 ) 74,167 72,622 Cash flow used in financing activities 8,500 (71,239 ) (60,340 )

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Liabilities Measured at Fair Value on Recurring Basis (Detail) (Fair Value, Measurements, Recurring, USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Prepaid and Other Current Assets | Commodity Contract | Physical Forward Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value disclosure	$ (307)
Prepaid and Other Current Assets | Commodity Contract | Exchange Traded Futures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value disclosure	542
Noncurrent Liabilities | Warrant
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability fair value disclosure	(10,900)
Noncurrent Liabilities | Embedded Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability fair value disclosure	$ (45)

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Changes in Capitalized Exploratory Well Costs (Detail) (USD $) In Thousands, unless otherwise specified	4 Months Ended		8 Months Ended	12 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2012 Successor Company	Dec. 31, 2012 Successor Company's Share of Piceance Energy	Aug. 31, 2012 Predecessor Company	Dec. 31, 2011 Predecessor Company	Aug. 31, 2012 Predecessor Company's Share of Piceance Energy	Dec. 31, 2011 Predecessor Company's Share of Piceance Energy
Balance at beginning of year			$ 8,770	$ 6,200
Additions to capitalized exploratory well costs pending the determination of proved reserves				29,226
Exploratory well costs included in property divestitures			(8,770)
Reclassified to proved oil and gas properties based on the determination of proved reserves				(26,656)
Capitalized exploratory well costs charged to dry hole expense
Balance at end of year				8,770
Exploratory well costs capitalized for one year or less after completion of drilling				8,770
Exploratory well costs capitalized for greater than one year after completion of drilling

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Summary of Claims

A summary of claims is as follows:

	Emergence-Date August 31, 2012				Year-ended December 31, 2012
	Filed Claims				Settled Claims								Remaining Filed Claims
									Consideration
	Count		Amount		Count		Amount		Cash		Stock		Count		Amount
U.S. Government Claims		3	$	22,364,000		—	$	—	$	—		—		3	$	22,364,000
Former Employee Claims		32		16,379,849		13		3,685,253		229,478		202,231		19		12,694,596
Macquarie Capital (USA) Inc.		1		8,671,865		—		—		—		—		1		8,671,865
Swann and Buzzard Creek Royalty Trust		1		3,200,000		—		—		—		—		1		3,200,000
Other Various Claims*		69		23,120,396		12		2,914,859		29,427		522		57		20,205,537
Total		106	$	73,736,110		25	$	6,600,112	$	258,905		202,753		81	$	67,135,998

	Subsequent to Year-ended December 31, 2012 through March 19, 2013
	Settled Claims								Remaining Filed Claims
					Consideration
	Count		Amount		Cash		Stock		Count		Amount
U.S. Government Claims		—	$	—	$	—		—		3	$	22,364,000
Former Employee Claims		12		11,750,904		278,338		1,361,452		7		943,692
Macquarie Capital (USA) Inc.		—		—		—		—		1		8,671,865
Swann and Buzzard Creek Royalty Trust		—		—		—		—		1		3,200,000
Other Various Claims*		13		581,607		397,754		108,123		44		19,623,930
Total		25	$	12,332,511	$	676,092		1,469,575		56	$	54,803,487

* Includes reserve for contingent/unliquidated claims in the amount of $10 million

Future Minimum Payments under Operating Leases That Have Remaining Term In Excess of One Year

Future minimum payments under operating leases that have a remaining term in excess of one year as of December 31, 2012 were as follows (in thousands):

2013	$	1,496
2014		1,496
2015		1,496
2016		1,496
2017		660
	$	6,644

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Statement of Operations for Piceance Energy (Detail) (Piceance Energy, USD $)	4 Months Ended
	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Oil, natural gas and natural gas liquids revenues	$ 19,391,000
Oil and gas operating expenses	9,100,000
Depletion, depreciation and amortization	8,523,000
Management fee	3,250,000
General and administrative	613,000
Total operating expenses	21,486,000
Operating income (loss)	(2,095,000)
Other income (expense)
Loss from derivatives	(918,000)
Interest expense and debt issue costs	(976,000)
Other income	14,000
Total other expense	(1,880,000)
Net loss	(3,975,000)
Equity Method Investments, Our Share
Schedule of Equity Method Investments [Line Items]
Oil, natural gas and natural gas liquids revenues	6,465,000
Oil and gas operating expenses	3,034,000
Depletion, depreciation and amortization	2,842,000
Management fee	1,084,000
General and administrative	204,000
Total operating expenses	7,164,000
Operating income (loss)	(699,000)
Other income (expense)
Loss from derivatives	(306,000)
Interest expense and debt issue costs	(325,000)
Other income	5,000
Total other expense	(626,000)
Net loss	$ (1,325,000)

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Disclosures About Capitalized Costs, Costs Incurred (Unaudited)

12 Months Ended

Dec. 31, 2012

Disclosures About Capitalized Costs, Costs Incurred (Unaudited)

(15) Disclosures About Capitalized Costs, Costs Incurred (Unaudited)

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

	Successor			Predecessor
	Period from September 1 through December 31, 2012			Period from January 1 through August 31, 2012 (1)			Year Ended December 31, 2011
Company:
Unproved properties	$	—		$	84		$	72,081
Proved properties		4,804			759,755			688,521
		4,804			759,839			760,602
Accumulated depreciation and depletion		(337	)		(642,172	)		(442,169	)
	$	4,467		$	117,667		$	318,433
Company’s Share of Piceance Energy:
Unproved properties	$	16,180
Proved properties		134,638
		150,818
Accumulated depreciation and depletion		(2,808	)
	$	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 accounting (see Note 2).

Costs incurred in oil and gas activities are as follows (in thousands):

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012		Year Ended December 31, 2011
Company:
Unproved property acquisition costs	$	—	$	—	$	452
Proved property acquisition costs		—		—		(51	)
Development costs incurred on proved undeveloped reserves		—		1,613		4,858
Development costs—other		—		—		39,980
Exploration and dry hole costs		—		—		98
Total	$	—	$	1,613	$	45,337
Company’s Share of Piceance Energy:
Unproved properties acquisition costs	$	206
Proved properties acquisition costs (1)		32,519
Development costs incurred on proved undeveloped reserves		—
Development costs—other		291
Exploration and dry hole costs		—
Total	$	33,016

Included in costs incurred are asset retirement obligation costs for all periods presented.

(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.

Changes in capitalized exploratory well costs are as follows (in thousands):

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Company:
Balance at beginning of year	$	—	$	8,770		$	6,200
Additions to capitalized exploratory well costs pending the determination of proved reserves		—		—			29,226
Exploratory well costs included in property divestitures		—		(8,770	)		—
Reclassified to proved oil and gas properties based on the determination of proved reserves		—		—			(26,656	)
Capitalized exploratory well costs charged to dry hole expense		—		—			—
Balance at end of year	$	—	$	—		$	8,770
Exploratory well costs capitalized for one year or less after completion of drilling	$	—	$	—		$	8,770
Exploratory well costs capitalized for greater than one year after completion of drilling		—		—			—
Balance at end of year	$	—	$	—		$	8,770
Company’s Share of Piceance Energy:
Balance at beginning of year	$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		—
Exploratory well costs included in property divestitures		—
Reclassified to proved oil and gas properties based on the determination of proved reserves		—
Capitalized exploratory well costs charged to dry hole expense		—
Balance at end of year	$	—
Exploratory well costs capitalized for one year or less after completion of drilling	$	—
Exploratory well costs capitalized for greater than one year after completion of drilling		—
Balance at end of year	$	—

The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same period.

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

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January 1 through August 31, 2012			Year Ended December 31, 2011
Company:
Revenue:
Oil and gas revenues	$	2,144	$	23,079		$	63,880
Expenses:
Production costs		1,688		16,980			29,157
Depletion and amortization		370		16,041			36,624
Exploration		—		2			338
Abandoned and impaired properties		—		151,347			419,851
Dry hole costs		—		—			355
Results of operations of oil and gas producing activities	$	86	$	(161,291	)	$	(422,445	)
Income from operations of properties sold, net	$	—	$	—		$	2,280
Gain on sale of properties		—		—			6,874
Income from results of discontinued operations of oil and gas producing activities	$	—	$	—		$	9,154
Company’s share of Piceance Energy:
Revenue:
Oil and gas revenues	$	6,464
Expenses:
Production costs		3,033
Depletion and amortization		2,808
Exploration		—
Abandoned and impaired properties		—
Dry hole costs		—
Results of operations of oil and gas producing activities	$	623
Total Company and Piceance Energy income from operations of oil and gas producing activities	$	709

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Principles of Consolidation and Basis of Presentation

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. Certain of our oil and gas activities may be conducted through partnerships and joint ventures. We will include our proportionate share of assets, liabilities, revenues and expenses from these entities in our consolidated financial statements. 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 Par Piceance Energy, LLC, which owns our investment in Piceance Energy (see Note 4), and Texadian Energy, Inc. (formerly known as SEACOR Energy Inc. (“Texadian”)), which we acquired December 31, 2012 (see Note 5).

Accounting for the Chapter 11 Filing

Accounting for the Chapter 11 Filing

The Predecessor followed the accounting prescribed by ASC 852. This accounting literature provides guidance for periods subsequent to a Chapter 11 filing regarding the presentation of liabilities that are and are not subject to compromise by the bankruptcy court proceedings, as well as the treatment of interest expense and presentation of costs associated with the proceedings. As a result of the reorganization, the realization of assets and the satisfaction of liabilities were subject to uncertainty. While operating as a debtor-in-possession under Chapter 11, Predecessor’s ability to sell or otherwise dispose of or liquidate assets or settle liabilities, were subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Credit Facility), in amounts other than those reflected in the accompanying consolidated financial statements of the Predecessor. The accompanying Predecessor consolidated financial statements for the year ended December 31, 2011 do not include any direct adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary as a consequence of the reorganization under the Plan.

The Reorganizations Topic of ASC 852, which is applicable to companies in Chapter 11, generally does not change the manner in which financial statements are prepared. However, it does require that the financial statements for periods subsequent to the filing of the Plan distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Amounts that can be directly associated with the reorganization and restructuring of the business must be reported separately as reorganization items in the statements of operations beginning in the quarter ending December 31, 2011. The balance sheet must distinguish pre-petition liabilities subject to compromise from both those pre-petition liabilities that are not subject to compromise and from post-petition liabilities. Liabilities that may be affected by a plan of reorganization must be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. In addition, cash provided by and used for reorganization items must be disclosed separately. The Company has applied the Reorganizations Topic of ASC 852 effective as of the Effective Date, and has segregated those items as outlined above for all reporting periods subsequent to such date.

Cash Equivalents

Cash Equivalents

We consider all highly liquid investments with maturities at date of acquisition of three months or less to be cash equivalents.

Restricted Cash

Restricted Cash

As of December 31, 2012, restricted cash consists of amounts held at a commercial bank to support our letter of credit facility totaling approximately $19.0 million (see Note 6). In addition, we have restricted cash of approximately $5.0 million designated to settle bankruptcy matters that is not available for operating activities (see Note 9).

Trade Receivables

Trade Receivables

As of December 31, 2012, Texadian’s customers primarily included major independent refining and marketing companies. Customers are required to pay in advance or are granted credit on a short-term basis when credit risks are considered minimal. We routinely review our trade receivables and make provisions for doubtful accounts based on existing customer and economic conditions; however, those provisions are estimates and actual results could differ from those estimates and those differences may be material. Trade receivables are deemed uncollectible and removed from accounts receivable and the allowance for doubtful accounts when collection efforts have been exhausted. As of December 31, 2012, we had no allowance for doubtful accounts. Additionally, we provide an accrual for oil and natural gas sales using the sales method by estimating oil and natural gas volumes and prices for months in which revenues have not been received using production and pricing information provided by the operator. Most of Texadian’s physical purchases and sales with the same counterparty are settled on a net basis and therefore Texadian’s receivables are recorded net of any corresponding payables.

Inventories

Inventories

As of December 31, 2012, Texadian’s inventories, which consist of in transit crude oil, are stated at the lower of cost (using the first-in, first-out method) or market. We record impairments, as needed, to adjust the carrying amount of inventories to the lower of cost or market.

Investments in Unconsolidated Affiliates

Investments in Unconsolidated Affiliates

Investments in operating entities where we have the ability to exert significant influence, but do not control the operating and financial policies, are accounted for using the equity method. Our share of net income of these entities is recorded as income (loss) from unconsolidated affiliates in the consolidated statements of operations.

At December 31, 2012, our investment in unconsolidated affiliates consisted of our ownership interest in Piceance Energy (see Note 4). Until November 2011, the Predecessor owned a 49.8% interest in DHS Drilling Company (“DHS”). The Predecessor’s representatives constituted a majority of the members of the board of directors of DHS and the Predecessor had the right to use all of the rigs owned by DHS on a priority basis and, accordingly, DHS was consolidated in these financial statements until we disposed of DHS in 2011.

Assets Held for Sale

Assets Held for Sale

As of December 31, 2012, we have classified our compressors as held for sale, which are recorded at the lower of cost or estimated net realizable value. These compressors are not in use and are not being depreciated.

Property and Equipment

Property and Equipment

We account for our oil and natural gas 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. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological or geophysical expenses and delay rentals for 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, and development costs is computed using the units-of-production method by individual fields (common reservoirs) using proved producing oil and natural gas reserves amortized as the related reserves are produced. Associated leasehold costs are depleted using the unit of production method based on total proved oil and natural gas reserves amortized as the related reserves are produced.

Other property and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives ranging from three to 15 years.

Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets

We recorded goodwill as a result of our acquisition of Texadian. Goodwill is attributable to the synergies 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, as a result of our acquisition of Texadian, 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.

Impairment of Goodwill and Long-Lived Assets

Impairment of Goodwill and Long-Lived Assets

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. Qualitative factors assessed for the reporting unit would include the competitive environments and financial performance of the reporting unit. 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, based upon a multiple of estimated earnings. 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. The fair value calculation uses level 3 (see Note 7) inputs and includes multiple assumptions and estimates, including the projected cash flows and discount rates applied. Changes in these assumptions and estimates could result in goodwill impairment that could materially adversely impact our financial position or results of operations.

Long-lived assets are reviewed for impairment quarterly or when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

Estimates of expected future cash flows represent our best estimate based on reasonable and supportable assumptions and projections. For proved properties, if the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized are permanent and may not be restored in the future.

We assess proved properties on an individual field basis for impairment each quarter when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For proved properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs.

For unproved properties, the need for an impairment charge is based on our plans for future development and other activities impacting the life of the property and our ability to recover our investment. When we believe the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. For the period from September 1 through December 31, 2012, there were no impairments recorded by the Successor. 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 to write-down these assets to fair value at that time. The Predecessor’s assets were further adjusted due to the application of fresh start accounting upon the Predecessor’s emergence from Chapter 11. The Predecessor recognized impairment expenses totaling approximately $151.3 million for the period January 1, 2012 through August 31, 2012 and $420.4 million for the year ended December 31, 2011, respectively.

Asset Retirement Obligations

Asset Retirement Obligations

Our asset retirement obligations arise from the plugging and abandonment liabilities for our oil and gas wells. The following is a reconciliation of our asset retirement obligations (in thousands):

	Successor		Predecessor
	Period from September 1 through December 31, 2012		Period from January  1 through August 31, 2012			Year Ended December 31, 2011
Asset retirement obligation – beginning of period	$	476	$	3,799		$	3,931
Accretion expense		36		178			273
Change in estimate		0		437			(135	)
Obligations incurred (from new wells)		0		—			385
Obligations settled		0		—			(296	)
Obligations on sold properties		0		—			(359	)
Settlement upon transfer to Piceance Energy		—		(3,938	)		—
Asset retirement obligation – end of period		512		476			3,799
Less: Current portion of asset retirement obligation		0		—			(292	)
Long-term asset retirement obligation	$	512	$	476		$	3,507

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

Derivatives and Other Financial instruments

Derivatives and Other Financial instruments

We may periodically enter into commodity price risk transactions to manage our exposure to ethanol, oil and gas 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.

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, we issued warrants (see Note 6) that are not considered to be indexed to our equity. Accordingly, these warrants are accounted for as liabilities. In addition, the Loan Agreement contains certain puts that are 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.

The carrying value of trade accounts receivable and accounts payable approximates fair value due to their short term nature. Our long-term debt is recorded on the amortized cost basis. We estimate its fair value to be approximately $10.9 million at December 31, 2012 using a discounted cash flow analysis and an estimate of the current yield (15.4%) by reference to market interest rates for term debt of comparable companies which is considered a level 3 fair value measurement (see Note 7). Our derivatives are recorded at fair value.

Accrued Settlement Claims

Accrued Settlement Claims

As of December 31, 2012, we have accrued approximately $8.7 million relating to claims resulting from our bankruptcy (See Note 9).

Income Taxes

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 based on a “more likely than not” standard, and to the extent this threshold is not met, a valuation allowance is recorded.

We recognize in the financial statements 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 2009, 2010, and 2011. 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.

Stock Based Compensation

Stock Based Compensation

We recognize the cost of share based payments over the period the employee provides service, generally the vesting period, and includes such costs in general and administrative expense in the 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

Revenue Recognition

Oil and Gas

Revenues are recognized when title to the products transfers to the purchaser. We follow the “sales method” of accounting for our natural gas and crude oil revenue, so that we recognize sales revenue on all natural gas or crude oil sold to its 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, 2012, our aggregate natural gas and crude oil imbalances were not material to our consolidated financial statements.

Marketing and Transportation

Marketing and Transportation

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.

Texadian will earn revenues from the sale of crude oil, blendstocks and refined products, the rental of rail cars, and through voyage affreightment contracts on leased-in liquid tank barges and towboats. Revenues and related costs from crude oil, blendstocks and refined products are recorded when title transfers to the buyer. Revenues from the rental of railcars are recognized ratably over the lease periods. Revenues from voyage affreightment contracts are generally recognized over the progress of the voyage while the related costs are expensed as incurred. Unearned revenues arise and are recorded as a liability when customers pay in advance for products or services.

Major Customers

Major Customers

For the year ended December 31, 2012 and 2011, two and three customers accounted for approximately 54% and 59%, respectively, of Texadian’s operating revenues (see Note 5). The loss of any of these customers could have a material adverse effect on our future results of operations.

For the period September 1, 2012 to December 31, 2012, we had one customer that accounted for 96% of the Sucessor’s total oil and natural gas sales. During the period from January 1, 2012 to August 31, 2012 we had two customer that accounted individually for 59% and 24%, respectively, of the Predecessor’s total oil and natural gas sales. For the year ended December 31, 2011, two customers accounted individually for 56% and 19%, respectively, of the Predecessor’s total oil and gas sales. Although a substantial portion of production is purchased by these major customers, we do not believe that the loss of a customer would have a material adverse effect on our business as other customers or markets would be accessible to us.

Foreign Currency Transactions

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 foreign currency losses, net in the accompanying consolidated statements of operations in the period in which the currency exchange rates change.

Use of Estimates

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 under fresh start accounting, fair value of assets and liabilities recorded under purchase accounting, oil and natural gas reserves, bad debts, depletion and impairment of oil and natural gas properties, income taxes and the valuation allowances related to deferred tax assets, derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.

Recently Adopted Guidance

Recently Adopted Guidance

Comprehensive Income—In June 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-05, related to ASC Topic 220, Comprehensive Income: Presentation of Comprehensive Income and in December 2011 the FASB issued ASU 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU 2011-05. These standards eliminate the current option to report other comprehensive income and its components in the statement of changes in equity. The adoption of this amendment in 2012 did not have a material effect on the presentation of our consolidated financial statements.

Fair Value Measurement—In May 2011, the FASB issued new guidance related to ASC Topic 820, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The new guidance results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and International Financial Reporting Standards (“IFRS”), changes some fair value measurement principles and requires additional disclosure. The ASU was effective for interim and annual periods beginning on or after December 15, 2011. The adoption of this amendment in 2012 did not have a material effect on the presentation of our consolidated financial statements.

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Changes in Estimated Quantities of Proved Reserves (Parenthetical) (Detail)	Dec. 31, 2012 MMcf		Dec. 31, 2012 Natural Gas MMcf	Dec. 31, 2012 Natural Gas Liquids bbl	Dec. 31, 2011 Weighted Average Natural Gas MMcf	Dec. 31, 2011 Weighted Average Natural Gas Liquids bbl	Aug. 31, 2012 Reorganized Delta Petroleum	Aug. 31, 2012 Laramie
Reserve Quantities [Line Items]
Ownership interest held in Piceance Energy, percentage							33.34%	66.66%
Estimated Proved Reserves	167,863	[1]	123,096	6,345,000	70,982	4,057,000

[1] MMcfe is based on a ratio of 6 Mcf to 1 barrel.

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Change in Our Equity Investment in Piceance Energy (Detail) (USD $) In Thousands, unless otherwise specified	4 Months Ended
	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Ending balance	$ 104,434
Piceance Energy
Schedule of Equity Method Investments [Line Items]
Beginning balance	105,344
Loss from unconsolidated affiliates	(1,325)
Capitalized drilling costs obligation paid	415
Ending balance	$ 104,434

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Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Data

	Predecessor									Successor
	Quarter Ended						Period from July 1 through August 31			Month Ended September 30,			Quarter Ended December 31,
(in thousands)	March 31,			June 30,
Year Ended December 31, 2012
Total revenue	$	9,910		$	7,703		$	5,466		$	584		$	1,560
Loss from continuing operations		(8,121	)		(10,003	)		(158,910	)		(2,002	)		(6,837	)
Reorganization Items(1)		5,342			5,910			(142,848	)		—			—
Net loss		(13,463	)		(15,913	)		(16,062	)		(2,002	)		(6,837	)
Net income (loss) per common share:(1)
Basic	$	(0.46	)	$	(0.55	)	$	(0.56	)	$	(0.01	)	$	(0.05	)
Diluted	$	(0.46	)	$	(0.55	)	$	(0.56	)	$	(0.01	)	$	(0.05	)
Total Assets(2)	$	374,527		$	364,752		$	142,911		$	138,447		$	189,582
Total Equity(2)	$	37,779		$	22,745		$	109,562		$	107,560		$	100,757
Cash Flow from Operations(1)	$	(3,641	)	$	(9,513	)	$	(7,108	)	$	(347	)	$	(4,289	)
Cash Flow from Investing(1)	$	(679	)	$	327		$	72,974		$	—			(17,690	)
Cash Flow from Financing(1)	$	—		$	5,000		$	(65,340	)	$	2,000			21,629

(1) In preparing the December 31, 2012 financial statements, we recorded an immaterial correction of an error pursuant to FASB ASC Topic 250, Accounting Changes and Error Corrections. The error related to the presentation of the gain on settlement of liabilities and fresh start accounting through the statement of equity as of September 1, 2012. As a result of application of the provisions of FASB ASC Topic 852, Reorganizations, the effect of the reorganization should have been reflected in the statement of operations of the Predecessor for the period from July 1 through August 31, 2012. The effect of the reorganization was previously disclosed in the footnotes to the Form 10-Q for the period ended September 30, 2012 and the Company believes the correction of this error is not material to its previously issued Predecessor financial statements. The Company has adjusted certain balances within the statement of operations and cash flows to correct this presentation error as follows:

	Predecessor
	Period from July 1, 2012 Through August 31, 2012
	As reported			Adjustments			As Corrected
	(in thousands)
Statement of Operations
Loss from continuing operations before income taxes, reorganization items and discontinued operations	$	(158,910	)	$	—		$	(158,910	)
Reorganization items
Professional fees and administrative costs		(10,719	)		—			(10,719	)
Gain on settlement of liabilities		—			168,332			168,332
Fresh Start Adjustments		—			(14,765	)		(14,765	)
Net loss	$	(169,629	)	$	153,567		$	(16,062	)
Cash Flow Data
Cash flow used in operations	$	(4,709	)	$	(2,399	)	$	(7,108	)
Cash flow provided by investing activities		(1,193	)		74,167			72,974
Cash flow used in financing activities		3,500			(68,840	)		(65,340	)

(2) Reflects true-up adjustments to the preliminary fresh start accounting values recorded at September 30, 2012.

	Predecessor
	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share amounts)
Year Ended December 31, 2011 (Predecessor)
Total revenue	$	17,715		$	16,882		$	16,546		$	12,737
Loss from continuing operations before income taxes, discontinued operations and cumulative effect		(27,424	)		(12,724	)		(429,973	)		(17,411	)
Net loss		(27,841	)		(963	)		(429,430	)		(11,877	)
Net income (loss) per common share:(1)
Basic	$	(1.00	)	$	(0.03	)	$	(15.40	)	$	(0.43	)
Diluted	$	(1.00	)	$	(0.03	)	$	(15.40	)	$	(0.43	)

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Consolidated Statement Of Changes In Equity (USD $)	Total	Predecessor USD ($)	Cancellation of Predecessor Common Stock USD ($)	Elimination of Predecessor Accumulated Deficit USD ($)	Issuance of Common Stock and Fresh Start Accounting USD ($)	Successor USD ($)	Common Stock Predecessor USD ($)	Common Stock Cancellation of Predecessor Common Stock USD ($)	Common Stock Elimination of Predecessor Accumulated Deficit USD ($)	Common Stock Issuance of Common Stock and Fresh Start Accounting USD ($)	Common Stock Successor USD ($)	Additional paid-in capital Share Predecessor USD ($)	Additional paid-in capital Share Cancellation of Predecessor Common Stock USD ($)	Additional paid-in capital Share Elimination of Predecessor Accumulated Deficit USD ($)	Additional paid-in capital Share Issuance of Common Stock and Fresh Start Accounting USD ($)	Additional paid-in capital Share Successor USD ($)	Treasury Stock Predecessor USD ($)	Treasury Stock Cancellation of Predecessor Common Stock USD ($)	Treasury Stock Elimination of Predecessor Accumulated Deficit USD ($)	Treasury Stock Issuance of Common Stock and Fresh Start Accounting USD ($)	Treasury Stock Successor USD ($)	Accumulated Deficit Predecessor USD ($)	Accumulated Deficit Cancellation of Predecessor Common Stock USD ($)	Accumulated Deficit Elimination of Predecessor Accumulated Deficit USD ($)	Accumulated Deficit Issuance of Common Stock and Fresh Start Accounting USD ($)	Accumulated Deficit Successor USD ($)	Total Par stockholders' Equity Predecessor USD ($)	Total Par stockholders' Equity Cancellation of Predecessor Common Stock USD ($)	Total Par stockholders' Equity Elimination of Predecessor Accumulated Deficit USD ($)	Total Par stockholders' Equity Issuance of Common Stock and Fresh Start Accounting USD ($)	Total Par stockholders' Equity Successor USD ($)	Non- controlling Interests Predecessor USD ($)	Non- controlling Interests Cancellation of Predecessor Common Stock USD ($)	Non- controlling Interests Elimination of Predecessor Accumulated Deficit USD ($)	Non- controlling Interests Issuance of Common Stock and Fresh Start Accounting USD ($)	Non- controlling Interests Successor USD ($)
Balance at Dec. 31, 2010		$ 511,595,000					$ 285,000					$ 1,635,783,000					$ (279,000)					$ (1,121,342,000)					$ 514,447,000					$ (2,852,000)
Balance (in shares) at Dec. 31, 2010							28,514,000										3,000
Net loss		(470,040,000)					0					0					0					(470,111,000)					(470,111,000)					71,000
Employee vesting of treasury stock held by Subsidiary (in shares)																	(3,000)
Employee vesting of treasury stock held by Subsidiary		85,000					0					(135,000)					279,000					0					144,000					(59,000)
Issuance of non-vested stock and stock-based compensation (in shares)							598,000
Issuance of non-vested stock and stock-based compensation		0					6,000					(6,000)					0					0					0					0
Forfeitures (in shares)							(55,000)
Forfeitures		0					0					0					0					0					0					0
Shares repurchased for withholding taxes (in shares)							(216,000)
Shares repurchased for withholding taxes		(996,000)					(3,000)					(993,000)					0					0					(996,000)					0
Sale of minority interest		2,744,000					0					0					0					0					0					2,744,000
Stock based compensation		6,837,000					0					6,741,000					0					0					6,741,000					96,000
Balance at Dec. 31, 2011		50,225,000					288,000					1,641,390,000					0					(1,591,453,000)					50,225,000					0
Balance (in shares) at Dec. 31, 2011		28,841,177					28,841,000										0
Net loss		(45,437,000)					0					0					0					(45,437,000)					(45,437,000)					0
Forfeitures (in shares)							(58,000)
Forfeitures		0					0					0					0					0					0					0
Stock based compensation		1,895,000					0					1,895,000					0					0					1,895,000					0
Balance at Aug. 31, 2012		6,683,000	0	0	102,879,000	109,562,000	288,000	(288,000)	0	1,477,000	1,477,000	1,643,285,000	288,000	(1,636,890,000)	101,402,000	108,085,000	0	0	0	0	0	(1,636,890,000)	0	1,636,890,000	0	0	6,683,000	0	0	102,879,000	109,562,000	0	0	0	0	0
Balance (in shares) at Aug. 31, 2012							28,783,000	(28,783,000)	0	147,656,000	147,656,000						0	0	0	0	0
Stock issued to settle bankruptcy claims (in shares)											203,000										0
Stock issued to settle bankruptcy claims						0					2,000					(2,000)					0					0					0					0
Net loss						(8,839,000)					0					0					0					(8,839,000)					(8,839,000)					0
Issuance of non-vested stock and stock-based compensation (in shares)											2,222,000										0
Issuance of non-vested stock and stock-based compensation						34,000					22,000					12,000					0					0					34,000					0
Balance at Dec. 31, 2012						$ 100,757,000					$ 1,501,000					$ 108,095,000					$ 0					$ (8,839,000)					$ 100,757,000					$ 0
Balance (in shares) at Dec. 31, 2012	147,700,000					150,080,927					150,081,000										0

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Reconciliation of Reportable Segment Assets to Consolidated Totals (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Segment Reporting, Asset Reconciling Item [Line Items]
Prepaid expenses	$ 177
Assets	189,582
Reportable Segment
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	178,788
Unallocated Amount to Segment
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 10,617

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Investments in Piceance Energy

12 Months Ended

Dec. 31, 2012

Investments in Piceance Energy

(4) Investments 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, and as a result, we do not meet the accounting criteria which require us to consolidate the joint venture. The LLC agreement that governs Piceance Energy 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, if approved by a majority of its board. If any member does not fund their share of the capital call, their 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 oil and gas properties and related assets with a borrowing base currently set at $140 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.

Piceance Energy holds various commodity hedging instruments to mitigate a portion of the effect of oil and natural gas price fluctuations. The contracts are in the form of costless collars of 10,000 MMBtu/day with floors of an average of $3.18 and ceilings of $4.22 as well as swaps of 10,000 MMBtu/day for an average price of $3.46 all through September 2014. Piceance Energy also holds gas gathering and processing contracts for a fixed rate expiring on various dates beginning in 2017 through 2032. Some of the contracts require a minimum throughput commitment.

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

	Period from September 1 through December 31, 2012
	(in thousands)
Beginning balance	$	105,344
Loss from unconsolidated affiliates		(1,325	)
Capitalized drilling costs obligation paid		415
Ending balance	$	104,434

Summarized balance sheet information and our share of the equity investment are as follows:

	December 31, 2012
	100%			Our Share
	(in thousands)
Assets
Cash and equivalents	$	234		$	78
Accounts receivable		4,836			1,612
Prepaids and other assets		1,205			402
Total current assets		6,275			2,092
Oil and gas property, successful efforts method		533,279			177,795
Other real estate and land		14,322			4,775
Office furniture and equipment		2,086			695
Total		549,687			183,265
Less: accumulated depletion, depreciation and amortization		(89,673	)		(29,897	)
Total property and equipment, net		460,014			153,368
Deferred issue costs and other assets, net		977			325
Total assets	$	467,266		$	155,785

	December 31, 2012
	100%			Our Share
	(in thousands)
Liabilities and Members’ Equity
Accounts payable and accrued liabilities	$	10,169		$	3,390
Oil and gas sales payable		1,657			552
Total current liabilities		11,826			3,942
Note payable		90,000			30,006
Derivative liabilities		1,525			508
Asset retirement obligation		2,844			948
Total non-current liabilities		94,369			31,462
Total liabilities		106,195			35,404
Members equity
Members’ equity		365,046			121,706
Accumulated deficit		(3,975	)		(1,325	)
Total members equity		361,071			120,381
Total liabilities and members’ equity	$	467,266		$	155,785

At December 31, 2012, our equity in the underlying net assets of Piceance Energy exceeded the carrying value of our investment by approximately $15.9 million. We attribute this difference, which is expected to be permanent, to lack of control and marketability discounts.

Summarized income statement information and our share for the period for which our investment was accounted for under the equity method is as follows:

	September 1 through December 31, 2012
	100%			Our Share
	(in thousands)
Oil, natural gas and natural gas liquids revenues	$	19,391		$	6,465
Oil and gas operating expenses		9,100			3,034
Depletion, depreciation and amortization		8,523			2,842
Management fee		3,250			1,084
General and administrative		613			204
Total operating expenses		21,486			7,164
Loss from operations		(2,095	)		(699	)
Other income (expense)
Loss from derivatives		(918	)		(306	)
Interest expense and debt issue costs		(976	)		(325	)
Other income		14			5
Total other expense		(1,880	)		(626	)
Net loss	$	(3,975	)	$	(1,325	)

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Fair Value Measurements Performed on Nonrecurring Basis (Detail) (USD $) In Thousands, unless otherwise specified	Aug. 31, 2012
Piceance Energy
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Investment in Piceance Energy	$ 105,344
Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Proved	4,587	[1],[2]
Other assets	4,239
Fair Value, Measurements, Nonrecurring | Frac tanks
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Other assets	1,400	[3]
Fair Value, Measurements, Nonrecurring | Compressors
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Other assets	2,800	[4]
Fair Value, Measurements, Nonrecurring | Miscellaneous
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Other assets	39	[5]
Fair Value, Measurements, Nonrecurring | Piceance Energy
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Line Items]
Investment in Piceance Energy	$ 105,344	[6]

[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 was valued using a market valuation technique which was based on published listings of similar equipment. We consider this to be a level 2 fair value measurement.

[4] The estimated fair value of the compressor units was valued using a market valuation technique based on standalone bids received by third-parties. We consider this to be a level 2 fair value measurement.

[5] 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.

[6] The estimated fair value of our investment in Piceance Energy is 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. A change in significant inputs such a reduction in commodity pricing or an increase in discount rates would result in a lower fair value.

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Earnings Per Share - Additional Information (Detail)	Dec. 31, 2012
Earnings Per Share Disclosure [Line Items]
Weighted average number of shares issuable under Warrants	9,592,125

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Oil and Gas Segment and Drilling Segment Revenues and Expenses Included In Discontinued Operations (Parenthetical) (Detail) (USD $)	8 Months Ended	12 Months Ended
	Aug. 31, 2012	Dec. 31, 2011
Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income tax benefit		$ 1,200,000
Predecessor
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Dry hole costs and impairments	151,347,000	420,402,000
Income tax benefit	0	(4,329,000)
Predecessor | Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Dry hole costs and impairments		608,000	[1]
Gain on sales of discontinued operations, net of tax		12,050,000	[2]
Oil & Gas | Columbia River, Greentown and Gulf Coast Properties | Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Dry hole costs and impairments		491,000
Oil & Gas | Predecessor | Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Dry hole costs and impairments		608,000	[1]
Gain on sales of discontinued operations, net of tax		6,874,000	[2]
Gain on sale of discontinued operations, before tax		8,900,000
Gain on sale of discontinued operations, tax		3,300,000
Drilling | Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Depreciation and amortization expense		2,700,000
Drilling | Predecessor | Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sales of discontinued operations, net of tax		5,176,000	[2]
Proceeds from sale of trucking assets		3,300,000
Gain from sale of trucking assets		$ 2,900,000

[1] Dry Hole Costs and Impairments. In 2011, we recorded impairments on our Columbia River, Greentown and Gulf Coast properties of $491,000 prior to their sale. In accordance with accounting standards, the impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction with the Wapiti Transaction were reflected as discontinued operations.

[2] Gain on sales of discontinued operations - oil and gas. In accordance with U.S. GAAP, we recognized a $5.6 million gain on sale ($8.9 million gain, net of $3.3 million of tax) for the year ended December 31, 2011 that is reflected in discontinued operations. In June 2011, DHS sold certain of its trucking assets for $3.3 million in proceeds and a gain of $2.9 million.

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Fresh Start Accounting and the Effects of the Plan (Tables)

12 Months Ended

Dec. 31, 2012

Presentation of Fresh Start Condensed Consolidated Balance Sheet Implementation of Plan and Adoption of Fresh Start Accounting

The following fresh start condensed consolidated balance sheet presents the implementation of the Plan and the adoption of fresh start accounting 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 accounting in accordance with ASC 852.

	August 31, 2012
	Predecessor			Plan of Reorganization Adjustments			Fresh Start Accounting Adjustments			Successor
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		0			3,446	(e)					3,446
Restricted cash		0			20,359	(d)					20,359
Trade accounts receivable, net		3,708			(1,727	)(a)		(1,981	)(g)		0
Prepaid assets		4,777						(4,777	)(g)		0
Prepaid reorganization costs		1,326						(1,326	)(g)		0
Total current assets		11,765									28,687
Property and equipment:
Oil and gas properties,
Unproved		84						(84	)(g)		0
Proved		759,755			(740,392	)(a)		(14,776	)(g)		4,587
Land		4,000			(4,000	)(a)					0
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)		0
Net property and equipment		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)				$	0
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)					0
7 % Senior convertible notes		150,000			(150,000	)(b)					0
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		0			6,335	(c)					6,335
Derivative liabilities		0			6,665	(c)					6,665
Asset retirement obligations		4,414			(3,938	)(a)					476
Total liabilities		357,273									33,349
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)		0
					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 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 extinguishment of secured debt in exchange for common stock of the Successor. On the Emergence Date, we issued 145,736,082 shares of our common stock and warrants to acquire 9,592,125 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 $0.70 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 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.

(d) Reflects settlement of other claims with common stock of Successor and cash. On the Emergence Date, we issued 1,919,733 shares of our common stock to various creditors. We estimated the fair value of our common stock to be $0.70 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 funding of the Recovery Trusts (see Note 9).

(f) Reflects cancellation of Predecessor common stock.

(g) 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.

(h) Reflects elimination of Predecessor accumulated deficit.

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Stockholders' Equity - Additional Information (Detail) (USD $)	1 Months Ended	8 Months Ended	12 Months Ended			12 Months Ended		12 Months Ended					12 Months Ended	1 Months Ended				12 Months Ended		8 Months Ended	12 Months Ended	1 Months Ended					12 Months Ended
	Jul. 12, 2011	Aug. 31, 2012	Dec. 31, 2011	Dec. 31, 2012	Dec. 20, 2012	Dec. 31, 2012 Restricted Stock	Dec. 31, 2012 Maximum	Dec. 31, 2012 Minimum	Dec. 31, 2012 Board Of Directors	Dec. 31, 2012 Board Of Directors Restricted Stock	Dec. 31, 2012 Board Of Directors Maximum	Dec. 31, 2012 Board Of Directors Minimum	Dec. 31, 2012 Employee Restricted Stock	Dec. 31, 2012 Incentive Plans Director	Dec. 31, 2012 Incentive Plans Chairperson of Audit Committee	Dec. 31, 2012 Incentive Plans Non Chairman Audit Committee	Dec. 31, 2012 Restatement	Dec. 31, 2012 Form S-1	Dec. 31, 2012 Form S-3	Aug. 31, 2012 Predecessor	Dec. 31, 2011 Predecessor	Jun. 21, 2011 Predecessor Common Stock	Dec. 31, 2012 7% Senior Unsecured Notes, due 2015	Mar. 15, 2005 7% Senior Unsecured Notes, due 2015 Predecessor	Dec. 31, 2012 3 3/4% Senior Convertible Notes, due 2037	Apr. 25, 2007 3 3/4% Senior Convertible Notes, due 2037 Predecessor	Dec. 31, 2012 Senior Unsecured Note	Dec. 31, 2012 Unsecured Debt
Class of Stock [Line Items]
Interest percentage of senior notes																							7.00%	7.00%	3.75%	3.75%
Maturity period																							2015	2015	2037	2037
Shares allotted to note holders																											145,736,082	1,919,733
Number of shares issuable under warrants				9,592,125			12,200,000
Number of shares authorized																	303,000,000
Common stock, shares authorized																	300,000,000				200,000,000
Preferred stock, shares authorized																	3,000,000				3,000,000
Preferred stock, par value																	$ 0.01				$ 0.01
Percentage of registrable shares with the right to require filing registration statement								15.00%
Expected Market Value Of Registrable Shares																		$ 15,000,000	$ 5,000,000
Percentage of demanding stockholder's registrable shares																		100.00%
Reverse split of the common stock	One-for-ten
Reverse split of the common stock, ratio	0.1
Common shares Issued									30,524
Common shares Issued amount									33,000												0
Share price				$ 0.70							$ 1.20	$ 1.00
Number of shares authorized					16,000,000
Non-vested shares Granted		0	598,836			2,191,834																489,227
Vesting period										1 year			5 years
Unrecognized compensation cost						2,400,000
Weighted average period						4 years 9 months 18 days
Annual retainer to amount														50,000	15,000	5,000
Annual grant of restricted stock														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	$ 8,000,000

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

Reportable Segment Assets

 At December 31, 2012, our reportable segment assets consisted of the following:

	Natural Gas and Oil Exploration and Production		Commodity Transportation and Marketing		Totals
Current assets	$	2,951	$	46,181	$	49,132
Net property and equipment		5,846		—		5,846
Investments in unconsolidated affiliates		104,434		—		104,434
Goodwill and other intangible assets		—		16,565		16,565
Assets held for sale		2,800		0		2,800
Other long term assets		3		8		11
Totals	$	116,034	$	62,754	$	178,788

Reconciliation of Reportable Segment Assets to Consolidated Totals

Reconciliation of reportable segment assets to out consolidated totals is as follows (in thousands):

	December 31, 2012
Total assets for reportable segments	$	178,788
Cash and restricted cash not allocated to segments		10,617
Prepaid expenses		177
Total assets	$	189,582

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Segment Information

12 Months Ended

Dec. 31, 2012

Segment Information

(14) Segment Information

Following our acquisition of Texadian, we have two business segments, (i) natural gas and oil exploration and production and (ii) commodity transportation and marketing. For the period from September 1 through December 31, 2012, all of the operations as reported on our consolidated statement of operations related to oil and natural gas activities. For the period from September 1 through December 31, 2012, expenditures for long term assets, including goodwill and other intangible assets totaled approximately $415,000 for natural gas and oil activities and approximately $17.4 million for commodity transportation and marketing activities, respectively. At December 31, 2012, our reportable segment assets consisted of the following:

	Natural Gas and Oil Exploration and Production		Commodity Transportation and Marketing		Totals
Current assets	$	2,951	$	46,181	$	49,132
Net property and equipment		5,846		—		5,846
Investments in unconsolidated affiliates		104,434		—		104,434
Goodwill and other intangible assets		—		16,565		16,565
Assets held for sale		2,800		0		2,800
Other long term assets		3		8		11
Totals	$	116,034	$	62,754	$	178,788

Reconciliation of reportable segment assets to out consolidated totals is as follows (in thousands):

	December 31, 2012
Total assets for reportable segments	$	178,788
Cash and restricted cash not allocated to segments		10,617
Prepaid expenses		177
Total assets	$	189,582

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Selected Quarterly Financial Data (Detail) (USD $)		2 Months Ended		3 Months Ended												8 Months Ended		12 Months Ended	1 Months Ended		3 Months Ended		4 Months Ended
	Dec. 31, 2012	Aug. 31, 2012 Predecessor		Jun. 30, 2012 Predecessor		Mar. 31, 2012 Predecessor		Dec. 31, 2011 Predecessor		Sep. 30, 2011 Predecessor		Jun. 30, 2011 Predecessor		Mar. 31, 2011 Predecessor		Aug. 31, 2012 Predecessor		Dec. 31, 2011 Predecessor	Sep. 30, 2012 Successor		Dec. 31, 2012 Successor		Dec. 31, 2012 Successor
Quarterly Financial Data [Line Items]
Total revenue		$ 5,466,000		$ 7,703,000		$ 9,910,000		$ 12,737,000		$ 16,546,000		$ 16,882,000		$ 17,715,000		$ 23,079,000		$ 63,880,000	$ 584,000		$ 1,560,000		$ 2,144,000
Loss from continuing operations		(158,910,000)		(10,003,000)		(8,121,000)		(17,411,000)		(429,973,000)		(12,724,000)		(27,424,000)		(177,033,000)		(487,531,000)	(2,002,000)		(6,837,000)		(11,596,000)
Reorganization Items		(142,848,000)	[1]	5,910,000	[1]	5,342,000	[1]												0	[1]	0	[1]
Net loss		(16,062,000)		(15,913,000)		(13,463,000)		(11,877,000)		(429,430,000)		(963,000)		(27,841,000)		(45,437,000)		(470,111,000)	(2,002,000)		(6,837,000)		(8,839,000)
Net income (loss) per common share:
Basic		$ (0.56)	[1]	$ (0.55)	[1]	$ (0.46)	[1]	$ (0.43)	[1]	$ (15.40)	[1]	$ (0.03)	[1]	$ (1.00)	[1]	$ (1.57)		$ (16.30)	$ (0.01)	[1]	$ (0.05)	[1]	$ (0.06)
Diluted		$ (0.56)	[1]	$ (0.55)	[1]	$ (0.46)	[1]	$ (0.43)	[1]	$ (15.40)	[1]	$ (0.03)	[1]	$ (1.00)	[1]	$ (1.57)		$ (16.30)	$ (0.01)	[1]	$ (0.05)	[1]	$ (0.06)
Total Assets	189,582,000	142,911,000	[2]	364,752,000	[2]	374,527,000	[2]	387,897,000								142,911,000	[2]	387,897,000	138,447,000	[2]	189,582,000	[2]	189,582,000	[2]
Total Equity		109,562,000	[2]	22,745,000	[2]	37,779,000	[2]	50,225,000								109,562,000	[2]	50,225,000	107,560,000	[2]	100,757,000	[2]	100,757,000	[2]
Cash Flow from Operations		(7,108,000)	[1]	(9,513,000)	[1]	(3,641,000)	[1]									(20,262,000)		990,000	(347,000)	[1]	(4,289,000)	[1]	(4,636,000)
Cash Flow from Investing		72,974,000	[1]	327,000	[1]	(679,000)	[1]									72,622,000		87,649,000	0	[1]	(17,690,000)	[1]	(17,690,000)
Cash Flow from Financing		$ (65,340,000)	[1]	$ 5,000,000	[1]	$ 0	[1]									$ (60,340,000)		$ (89,967,000)	$ 2,000,000	[1]	$ 21,629,000	[1]	$ 23,629,000

[1] In preparing the December 31, 2012 financial statements, we recorded an immaterial correction of an error pursuant to FASB ASC Topic 250, Accounting Changes and Error Corrections. The errors related to the presentation of the gain on settlement of liabilities and fresh start accounting through the statement of equity as of September 1, 2012. As a result of application of the provisions of FASB ASC Topic 852, Reorganizations, the effect of the reorganization should have been reflected in the statement of operations of the Predecessor for the period from July 1 through August 31, 2012. The effect of the reorganization was previously disclosed in the footnotes to the Form 10-Q for the period ended September 30, 2012 and the Company believes the correction of this error is not material to its previously issued Predecessor financial statements. The Company has adjusted certain balances within the statement of operations and cash flows to correct this presentation error as follows: Predecessor Period from July 1, 2012 Through August 31, 2012 As reported Adjustments As Corrected (in thousands) Statement of Operations Loss from continuing operations before income taxes, reorganization items and discontinued operations $ (158,910 ) - $ (158,910 ) Reorganization items Professional fees and administrative costs (10,719 ) - (10,719 ) Gain on settlement of liabilities 168,332 168,332 Fresh Start Adjustments (14,765 ) (14,765 ) Net loss $ (169,629 ) $ 156,767 $ (16,062 ) Cash Flow Data Cash flow used in operations $ (17,863 ) $ (2,399 ) $ (20,262 ) Cash flow provided by investing activities (1,545 ) 74,167 72,622 Cash flow used in financing activities 8,500 (71,239 ) (60,340 )

[2] Reflects true-up adjustments to the preliminary fresh start accounting values recorded at September 30, 2012. Predecessor Quarter Ended March 31, June 30, September 30, December 31, (In thousands, except per share amounts) Year Ended December 31, 2011 (Predecessor) Total revenue $ 17,715 $ 16,882 $ 16,546 $ 12,737 Loss from continuing operations before income taxes, discontinued operations and cumulative effect (27,424 ) (12,724 ) (429,973 ) (17,411 ) Net loss (27,841 ) (963 ) (429,430 ) (11,877 ) Net income (loss) per common share:(1) Basic $ (1.00 ) $ (.03 ) $ (15.40 ) $ (.43 ) Diluted $ (1.00 ) $ (.03 ) $ (15.40 ) $ (.43 )