Magnum Hunter Resources 10K 2007 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007 or
o	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from __________to_________

Commission file number: 333-132596

Petro Resources Corporation

(Name of registrant as specified in its charter)

DELAWARE	86-0879278
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

777 Post Oak Boulevard, Suite 910, Houston, Texas 77056

(Address of principal executive offices, including zip code)

Registrant’s telephone number including area code: (832) 369-6986

Securities registered under Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
$0.01 par value Common Stock	American Stock Exchange

Securities registered under Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o Nox

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o Nox

Indicate by check mark if 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 past 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 Noo

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the 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.o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act):

Large accelerated filer __ Accelerated filer __ Non-accelerated filer __ Smaller reporting companyx

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o Nox

State the aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $26,053,348.

As of March 20, 2008, 36,634,372 shares of the registrant’s common stock were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for its Annual Meeting of Stockholders for 2008 to be filed with the Commission within 120 days after the close of its fiscal year are incorporated by reference into Part III hereof.

FORM 10-K ANNUAL REPORT

FISCAL YEAR ENDED DECEMBER 31, 2007

PETRO RESOURCES CORPORATION

Item		Page
PART I

1.	Business	3
1A.	Risk Factors	16
1B.	Unresolved Staff Comments	25
2.	Properties	25
3.	Legal Proceedings	28
4.	Submission of Matters to a Vote of Security Holders	28


PART II

5.	Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
6.	Selected Financial Data	30
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
7A.	Quantitative and Qualitative Disclosures About Market Risk	36
8.	Financial Statements and Supplementary Data	37
9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	38
9A(T).	Controls and Procedures	38
9B.	Other Information	38


PART III

10.	Directors, Executive Officers and Corporate Governance	39
11.	Executive Compensation	39
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	40
13.	Certain Relationships and Related Transactions, and Director Independence	40
14.	Principal Accountant Fees and Services	40
15.	Exhibits and Financial Statement Schedules	40

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CAUTIONARY NOTICE

This annual report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Those forward-looking statements include our expectations, beliefs, intentions and strategies regarding the future. Such forward-looking statements relate to, among other things, our proposed exploration and drilling operations on our various properties, the expected amount of capital required to finance our 2008 capital budget, the expected production and revenue from our various properties, and estimates regarding the reserve potential of our various properties. These and other factors that may affect our results are discussed more fully in “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this report. We caution readers not to place undue reliance on any forward-looking statements. We do not undertake, and specifically disclaim any obligation, to update or revise such statements to reflect new circumstances or unanticipated events as they occur, except as required by law, and we urge readers to review and consider disclosures we make in this and other reports that discuss factors germane to our business. See in particular our reports on Forms 10-K, 10-Q, and 8-K subsequently filed from time to time with the Securities and Exchange Commission.

PART I

Item 1.

BUSINESS

Industry terms used in this report are defined in the Glossary of Oil and Natural Gas Term located at the end of this Item 1.

Overview

Petro Resources Corporation and subsidiaries (“we,” “our” or “the Company”) is an independent oil and natural gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects in the United States. We act as a non-operator, which means we do not directly manage exploration, drilling or development operations. Instead, we pursue interests in oil and gas properties in joint ownership with oil and gas companies that have exploration, development and production expertise.

Our business strategy is designed to create and maximize shareholder value by leveraging the knowledge and expertise of our industry partners with regard to specific oil and natural gas projects, coupled with the energy knowledge and experience of our management team, in an effort to rapidly grow our diversified portfolio of oil and natural gas producing properties. We intend to achieve a balanced portfolio of producing properties by participating in oil and natural gas projects, both onshore and offshore, targeting low-to-medium risk projects that provide meaningful reserve, production and cash flow growth. We focus our acquisition pursuit on oil and natural gas properties and prospects principally located in the Gulf of Mexico, Texas, North Dakota, Louisiana, Kentucky, and New Mexico. We currently own interests in approximately 259,123 gross (48,334 net) leasehold acres, of which 240,826 gross (41,648 net) acres are classified as undeveloped acreage.

In July 2005, we acquired our initial interest in drilling prospects and commenced drilling activities in November 2005. In December 2005, we commenced production operations from our first oil and gas prospects and received our first revenues from oil and gas production in February 2006. In the first quarter of 2007, we acquired oil and gas producing assets in the Williston Basin area of North Dakota. As of March 15, 2008, we held interests in approximately 162 producing wells in Texas, Louisiana and North Dakota. We also have exploratory drilling prospects located in Texas, North Dakota, Louisiana, New Mexico, Kentucky, and the Gulf of Mexico.

As of December 31, 2006, our net total proved reserves were approximately 27,249 boe of which 7,900 boe were crude oil reserves. As of December 31, 2007, our estimated net total proved reserves had grown to approximately 2,716,602 boe (net of production) of which approximately 2,369,600 boe were crude oil reserves and 347,002 boe were natural gas reserves. The increase in net total proved reserves is a result of our Williston Basin acquisition that closed on February 16, 2007, positive results from enhanced oil recovery operations in North Dakota, successful exploratory drilling success in our Williston Basin joint venture and in our Cinco Terry Project in Crockett County, Texas. The increase excludes additional reserves attributable to our 5.3% limited partnership interest in Hall-Houston Exploration II, L.P.

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Our executive offices are located at 777 Post Oak Blvd., Suite 910, Houston, TX 77056, and our telephone number is (832) 369-6986. Our web site is www.petroresourcescorp.com. Additional information which may be obtained through our web site does not constitute part of this annual report on Form 10-K. A copy of this annual report on Form 10-K is located at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the SEC’s Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings at www.sec.gov.

Recent Developments

During fiscal 2007 through the date of this report, we have engaged in the following transactions:

Williston Basin Properties. On February 16, 2007, we acquired an approximately 43% average working interest in 15 fields located in the Williston Basin in North Dakota. Pursuant to a purchase and sale agreement dated December 11, 2006 between Eagle Operating Inc. (“Eagle”), of Kenmare, North Dakota, and our newly formed wholly-owned subsidiary, PRC Williston LLC, a Delaware limited liability company, PRC Williston acquired 50% of Eagle’s working interest in approximately 15,000 acres and 150 wells.

As consideration for purchasing the working interest in the Williston Basin properties, PRC Williston paid $12.7 million and we issued 3,144,655 shares of our common stock valued at $10.7 million to Eagle. In addition, PRC Williston agreed to contribute up to $45 million in development capital towards 100% of the mutually agreed upon joint capital costs of the existing secondary recovery and development program and in other joint participations with Eagle over a three year period. For a period of 36 months following the closing, Eagle has guaranteed that PRC Williston’s share of gross monthly production revenue from the properties shall not be less than the financial equivalent of 300 barrels of oil per day multiplied by the number of days in a given month (the product referred to as the “production floor”). In the event that our net share of gross production for any month is not at least equal to the production floor, Eagle shall pay to us, in cash, an amount equal to the difference between the production floor and the actual net barrels to our interest multiplied by the average price of crude paid for the oil production from the properties for that month (the “production floor payment”). During the 36 month period, Eagle shall be entitled to recover production floor payments previously made for any month in which our net share of oil production exceeds the production floor, by way of our cash payment not to exceed the amount by which of our net share of oil production exceeds the production floor (a “production floor reimbursement”). At the end of the 36 month period, we will be obligated to pay to Eagle, in cash, the amount of cumulative production floor payments, net of any production floor reimbursements. As of December 31, 2007, the “production floor reimbursement” account had a zero balance.

In connection with the acquisition, PRC Williston entered into a $75 million Credit Agreement dated February 16, 2007 with certain lenders, arranged by Petrobridge Investment Management, LLC. Pursuant to the Credit Agreement, as of December 31, 2007, the lenders have advanced PRC Williston a total of $25,375,225 for purposes of financing the acquisition of its interest in the Williston Basin fields, including certain transaction costs and fees, its costs of drilling and development of oil and gas properties, and general working capital.

All funds borrowed by PRC Williston under the credit facility bear interest at a rate equal to (x) the greater of the prime rate or 7.5%, plus (y) 2%, with interest payable monthly. The principal amount of advances outstanding under the credit facility are repayable monthly in an amount approximating 100% of PRC Williston’s cash on hand (from any source) less all permitted costs and expenses paid by PRC Williston for the monthly period.

PRC Williston’s obligations under the credit facility have been secured by its grant of a first priority security interest and mortgage on all assets of PRC Williston held now and in the future. We have also guaranteed the performance of PRC Williston’s obligations under the credit facility and related agreements by way of a Guaranty and Pledge Agreement dated February 16, 2007. Pursuant to the Guaranty and Pledge Agreement, we have secured our guarantee by granting to the lenders a first priority security interest in our ownership interest in PRC Williston.

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The credit facility contains a number of covenants imposing significant restrictions on us, including restrictions on our repurchase of, and payment of dividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets and create liens on our assets. These restrictions may affect our ability to operate our business, to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial conditions and results of operations.

The credit agreement also obligates PRC Williston to comply with certain financial covenants including a minimum current ratio beginning with the quarter ended June 30, 2007, a minimum interest coverage ratio and minimum debt coverage ratios. Subsequent to June 30, 2007, PRC Williston entered into agreements with the lenders to postpone the calculation of the financial covenants and waive various financial covenants until the quarter ended December 31, 2007. There can be no assurance that we will be able to meet the financial covenants, and if we fail to satisfy or obtain waivers for these covenants, we would be subject to the default provisions of the agreement. All of the assets of our operating subsidiary are pledged to secure the obligations under our credit facility. Our lack of unencumbered collateral could materially and adversely affect our ability to obtain, or increase the cost of obtaining, additional financing in the future.

Concurrent with the acquisition, PRC Williston entered into equity participation agreements with two unaffiliated parties, related to the lenders pursuant to which PRC Williston has agreed to pay to the two parties an aggregate of 12.5% of all equity distributions (“participation interest”) paid to the owners of PRC Williston, which at this time is 100% owned by Petro Resources Corporation. Pursuant to the equity participation agreements, the participation interest may be converted into a 12.5% working interest at the earlier of February 16, 2011 or the date of repayment of the credit facility. In addition, PRC Williston granted each of the two parties a 2% of 8/8ths overriding royalty interest, proportionally reduced by our net revenue interest percentage, in the oil and gas leases held by PRC Williston. Under the Credit Agreement, we were required to make an equity contribution of at least $5 million to PRC Williston within 180 days of the closing date of the acquisition of the Williston Basin properties. In September 2007, we entered into amendments to the Credit Agreement to extend such equity contribution date. In consideration of such extensions, we paid the lenders $375,000. In November 2007, we paid $12 million of indebtedness under the Credit Agreement. As of December 31, 2007, the current balance under the Credit Agreement is $14.3 million.

Series A Preferred Stock. On April 3, 2007, we completed the sale of 2,240,467 shares of our Series A Convertible Preferred Stock to two funds managed by Touradji Capital Management, LP in consideration of the Touradji funds’ (i) payment of $2 million; (ii) return of 1,573,800 shares of our common stock purchased in previous periods; and (iii) return of 160,000 common stock purchase warrants held by the funds with a deemed aggregate value of $4,721,400, or $3.00 per common share. We have cancelled both the returned common shares and the warrants. The total aggregate stated value of the Series A Preferred Stock sold was $6,721,401.

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Follow-On Public Offering. On November 2007, we closed the public offering of 16,100,000 shares of our common stock at a price of $2.00 per share, which included 2,100,000 shares of common stock sold pursuant to the exercise of the underwriters’ over-allotment option. We received approximately $27.46 million of offering proceeds, net of underwriters’ discounts and related expenses. Canaccord Adams Inc. served as the managing underwriter of the offering.

Our Oil and Gas Operations

We are committed to a corporate strategy of participating in producing and undeveloped oil and gas properties and exploratory drilling as a non-operator. An oil and gas operator is the party that takes primary responsibility for management of the day-to-day exploration, development and production activity, either by carrying out those activities directly or by contracting with third parties for the provision of some or all of such services. Instead of engaging in active exploration, development and production operations, we focus primarily on the search for and analysis and acquisition of interests in oil and gas properties and drilling prospects. As a non-operator, we participate by taking working interests in these properties with an industry partner functioning as the operator, as we have done in the Williston Basin properties. We also purchase leases with the intent to sell a portion of the interest to an unaffiliated third party who will serve as the operator while we retain a working interest, as we did with the Palo Duro Basin acreage. Additionally, we participate by direct investment in partnerships or other vehicles engaged in exploration and production, as we did with our investment in Hall-Houston Exploration II, L. P.

As a non-operator we believe we are able to leverage off the recognized geological, geophysical, and operational expertise of operators in certain geological provinces without having to hire and maintain a large in-house staff with specific expertise in those various geological areas. We expect to bear only a small portion of the operator’s overall geological and geophysical costs and receive in turn the full value of the specialized expertise of the operator’s staff. We believe we are able to further leverage and diversify by partnering or participating with several highly respected operators in different areas of the country. While we are confident of the expertise of our operator, we believe it is in our best interests to have certain qualified employees to review acquisitions, development and reserve value determinations, and will undertake to add such employees from time to time as the need arises. We may decide in the future to become an operator should the right opportunity present itself.

We invest primarily in domestic oil and natural gas interests, including producing properties, prospects, leases, wells, mineral rights, working interests, royalty interests, overriding royalty interests, net profits interests, production payments, farm-ins, drill to earn arrangements, partnerships, easements, rights of way, licenses and permits, in the Gulf of Mexico, Texas, North Dakota, New Mexico, Louisiana and Kentucky.

Our Strategy

It is our belief that the exploration and production industry’s most significant value creation occurs through the drilling of successful exploratory wells and the enhancement of oil recovery in mature fields. Our goal is to create significant value while maintaining a low cost structure. To this end, our business strategy includes the following elements:

Participation in exploration prospects with proven operators. We intend to pursue prospects in partnership with other companies that have exploration, development and production expertise. We will participate as a non-operator and will evaluate each prospect based on its geological and geophysical merits and, in large part, on the operator’s track record and resources.

Negotiated acquisitions of properties. We intend to acquire producing properties based on our view of the pricing cycles of oil and natural gas and available exploration and development opportunities of proved, probable and possible reserves.

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Leasing of prospective acreage. In the course of our business, we may identify drilling opportunities on properties that have not yet been leased. We may take the initiative to lease prospective acreage and sell all or any portion of the leased acreage to other companies that want to participate in the drilling and development of the prospect acreage.

Controlling Costs. We intend to maximize our returns on capital by minimizing our expenditures on general and administrative expenses. We also intend to minimize initial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that have already invested capital in such. We also intend to outsource our geological, geophysical, reservoir engineering and land functions in order to help reduce capital requirements.

Our operating strategy is to participate as a non-operator in oil and natural gas properties and drilling prospects. We intend to employ the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We will also pursue alliances with third parties in the areas of geological and geophysical services and prospect generation, evaluation and leasing as it relates to project-specific opportunities. As a non-operator, we intend to rely on unaffiliated third party operators to drill, produce and market our oil and natural gas. We believe that by limiting our overhead costs, we will be able to better control total costs and retain flexibility in terms of project management.

We intend to use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. We may enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts; however, it is our preference to utilize hedging strategies that provide downside commodity price protection without unduly limiting our revenue potential in an environment of rising commodity prices. We use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In the future we may also be required by our lenders to hedge a portion of production as part of any financing.

It is our long-term goal to achieve a well diversified and balanced portfolio of oil and natural gas producing properties located onshore North America and offshore in the Gulf of Mexico. In addition to geographic diversification, we also plan to target a balanced reserve mix between oil and natural gas, as well as conventional and unconventional resource plays.

At the present time, we have seven employees, including our five executive officers. We have developed an operating strategy that is based on our participation in oil and gas properties and drilling prospects as a non-operator. We intend to employ the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We will also pursue alliances with third parties in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. As a non-operator, we intend to rely on unaffiliated third party operators to drill, produce and market our oil and natural gas. We believe that by limiting our management and employee costs, we may be able to better control total costs and retain flexibility in terms of project management.

Principal Oil and Gas Interests

Williston Basin Properties. On February 16, 2007, we acquired approximately 43% average working interest in 15 fields located in the Williston Basin in North Dakota. Pursuant to a Purchase and Sale Agreement dated December 11, 2006 between Eagle Operating Inc, of Kenmare, North Dakota, and our newly formed wholly-owned subsidiary, PRC Williston LLC, a Delaware limited liability company, PRC Williston acquired 50% of Eagle’s working interest in approximately 15,000 acres and 150 wells which were producing approximately 260 barrels of oil per day net to PRC Williston’s interest. As of December 31, 2007, the fields were producing at a rate of approximately 347 barrels of oil per day net to PRC Williston’s interest. Eagle is the operator of the Williston Basin properties. The properties are secondary water flood re-pressurization candidates. Eagle has begun and will continue repressurization in the properties and subsequent conventional and horizontal drilling operations to increase production rates. Based on the 2007 year-end reserve report prepared for us by Cawley Gillespie & Associates, Inc., independent petroleum consultants, these properties have total proved reserves totaling 2,116,297 boe representing an increase of approximately 566,897 boe net of production from the date of acquisition. See, Item I “Business - Recent Developments” above for a summary of the Purchase and Sale Agreement and related $75 million credit facility.

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Secondary recovery efforts are under way in seven of the 15 producing fields. All fields in which repressurization has begun are responding to this secondary recovery effort. The North Grano Field is fully into secondary recovery with three new producing wells drilled during 2007 and has seen gross field production increase from 20 bbls of oil per day (pre injection rate) to 146 bbls per day, an increase of 730%.

We have budgeted $13.0 million to the Williston Basin for 2008 activity of which we expect to spend $9.3 million on development efforts.

Permian Basin, Cinco Terry Project. We have a 10% working interest in an exploratory prospect area in Crockett County, Texas with oil and natural gas potential from multiple horizons. The prospect is operated by Approach Resources, Inc. The prospect area consists of approximately 18,500 gross acres. As of the date of this report, 20 of 22 wells have been successfully drilled, completed and turned to sales. The operator has informed us that it intends to drill up to 36 additional wells in this prospect area during 2008. Gross production from the wells we participate in were producing 4,300 mcf per day and 326 barrels of oil per day as of December 31, 2007, of which we had a 6.7% net revenue interest. We have budgeted $4.1 million for operations in 2008 for this project.

Hall-Houston Exploration II, L. P. In April 2006, we purchased a 5.3% limited partners interest in Hall-Houston Exploration II, L. P., an oil and gas exploration and development partnership that has operations focused primarily offshore in the Gulf of Mexico. The purchase of our limited partner interest in the partnership required that we commit to contribute up to $8.0 million to the capital of the partnership.

Hall-Houston Exploration II, L. P. is managed by Hall-Houston Exploration Partners, L.L.C. The president and chief financial officer of Hall-Houston Exploration Partners, L.L.C. are Gary L. Hall and Brad Bynum, respectively, both of whom presently serve on our board of directors. In addition, Gary L. Hall is the brother of our chief executive officer, Wayne P. Hall. Wayne P. Hall has no direct or indirect ownership interest in Hall-Houston Exploration Partners, L.L.C. or Hall-Houston Exploration II, L. P., except through his ownership interest in our company. We invested in Hall-Houston Exploration II, L. P. on the same terms as all other limited partner investors in the partnership.

As of December 31, 2007, we had funded approximately $3.9 million of our $8.0 million commitment. We have assumed for purposes of planning and budgeting that we will be required to fund the remaining $4.1 million commitment during the remainder of fiscal 2008.

To date, Hall-Houston Exploration II, L.P. has drilled 18 wells, 14 of which were successful. As stated above, we expect to completely fulfill our capital commitments under the partnership in 2008. The general partner or Hall-Houston Exploration II, L.P. has advised us that three wells are planned to be drilled during the remainder of 2008.

Chalma Basin, El Vado East Prospect. The El Vado East prospect is a Mancos Shale exploratory oil prospect encompassing a total of 90,000 gross acres located in the Chama Basin in northern New Mexico. We own a 10% working interest and an 8.1% net revenue interest in the property. This prospect has oil and gas potential in three formations. The operator, Approach Resources, intends to drill the initial well on the acreage by mid-2008. We have budgeted $400,000 to participate in four Mancos Shale wells to be drilled during 2008.

Illinois Basin, Boomerang Prospect. In August 2006, we acquired a 10% working interest in an exploratory prospect in southwestern Kentucky at an acquisition cost of $339,368. Our interest was acquired from Approach Resources, Inc., who also serves as the operator. The prospect consists of approximately 74,000 gross acres located in the southwestern Kentucky region of the Illinois basin, and is prospective for natural gas from a horizon of shallow shale that is present at depths between 1,500 and 3,500 feet. Our working interest was subsequently reduced from 10% to 6.8% due to an unaffiliated working interest owner exercising their right to purchase a 33% gross working interest in the Boomerang Prospect. Three wells were drilled in the first quarter of 2007, of which two wells are expected to be completed as producing wells during 2008 and one well was plugged and abandoned due to well bore conditions. The operator has scheduled two vertical and three horizontal wells for 2008 to further test the productivity of the shale in this region.

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Unita Basin, South San Arroyo Prospect. In June 2006, we acquired an 85% working interest in a 20,300 gross acre shallow natural gas and oil exploratory prospect located in eastern Utah, just to the west of Grand Junction, Colorado. We do not anticipate any activity in this prospect area in the near future.

Palo Duro Basin. In December 2005 and January 2006, we acquired leases covering approximately 33,000 gross and 23,800 net mineral acres in the Palo Duro Basin located in Floyd and Motley Counties, Texas. Four leases were acquired for acquisition costs and expenses of approximately $2,550,000. Two of the leases covering approximately 9,300 net acres have primary terms of five years, one lease covering approximately 13,750 net acres has a primary term of four years and one lease covering approximately 750 net acres has a primary term of three years. There has been no activity on this prospect to date.

Competition

We compete with numerous other companies in virtually all facets of our business. Our competitors in the exploration, development, acquisition and production business include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater financial resources and in-house technical expertise than we do.

Marketing and Pricing

We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.

Our revenues, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of natural gas and crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:

·		changes in global supply and demand for oil and natural gas;
·		the actions of the Organization of Petroleum Exporting Countries, or OPEC;
·		the price and quantity of imports of foreign oil and natural gas;
·		acts of war or terrorism;
·		political conditions and events, including embargoes, affecting oil-producing activity;
·		the level of global oil and natural gas exploration and production activity;
·		the level of global oil and natural gas inventories;
·		weather conditions;
·		technological advances affecting energy consumption; and
·		the price and availability of alternative fuels.

Form time to time, we enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:

·		our production and/or sales of natural gas are less than expected;
·		payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
·		the counter party to the hedging contract defaults on its contract obligations.

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In addition, hedging arrangements limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, we where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.

As of December 31, 2007, we had the following hedges in place:

	Barrels per quarter	Barrels per day	Price per barrel
2008
First quarter	15,400	169	$66.74
Second quarter	14,446	159	$73.23
Third quarter	12,843	140	$71.47
Fourth quarter	9,200	100	$65.70

2009
First quarter	8,225	91	$65.62
Second quarter	6,825	75	$65.40
Third quarter	6,900	75	$65.40
Fourth quarter	6,900	75	$65.40

2010
First quarter	4,425	49	$65.40

Government Regulations

General. Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and local laws and regulations. The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impact our operations and can affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different than our competitors. Matters regulated include permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements for the operation of wells, and taxation of production. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gas and other substances and materials produced or used in connection with oil and natural gas operations. While we believe we will be able to substantially comply with all applicable laws and regulations, the requirements of such laws and regulations are frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect on our actual operations.

Federal Income Tax. Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, our domestic “intangible drilling and development costs” and to claim depletion on a portion of our domestic oil and natural gas properties based on 15% of our oil and natural gas gross income from such properties (up to an aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas).

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Environmental Matters. The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoining property, giving rise to additional liabilities.

A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing and may, in addition to other laws, impose liability in the event of discharges, whether or not accidental, failure to notify the proper authorities of a discharge, and other noncompliance with those laws. Compliance with such laws and regulations may increase the cost of oil and gas exploration, development and production, although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that dispose or arrange for disposal of the hazardous substances found at the time. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and severable liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA because our jointly owned drilling and production activities generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA.

The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

The Oil Pollution Act of 1990 (“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. 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 federal safety, construction or operating regulations. Few defenses exist to the liability imposed by OPA. In addition, to the extent we acquire offshore leases and those operations affect state waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws. OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. We cannot predict whether the financial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or impose substantial additional annual costs to us or otherwise materially adversely affect us. The impact, however, should not be any more adverse to us than it will be to other similarly situated owners or operators.

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The Federal Water Pollution Control Act Amendments of 1972 and 1977 (“Clean Water Act”) imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of crude oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from crude oil and natural gas production. The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In North Dakota, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells in that state. Failure to abide by our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

The Clean Air Act of 1963 and subsequent extensions and amendments, known collectively as the “Clean Air Act”, and state air pollution laws adopted to fulfill its mandate provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.

There are numerous state laws and regulations in the states in which we operate which relate to the environmental aspects of our business. These state laws and regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality.

We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you that environmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks generally are not fully insurable.

In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

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Federal Leases. For those operations on federal oil and gas leases, such operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies. In addition, on federal lands in the United States, the Minerals Management Service ("MMS") prescribes or severely limits the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, MMS prohibits deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the MMS has been engaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculating royalties owed to the government. The natural gas and crude oil industry as a whole has resisted the proposed rules under an assumption that royalty burdens will substantially increase. We cannot predict what, if any, effect any new rule will have on our operations.

Other Laws and Regulations. Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which we have production, could be to limit the number of wells that could be drilled on our properties and to limit the allowable production from the successful wells completed on our properties, thereby limiting our revenues.

Employees

We have seven employees, including our five executive officers. For the foreseeable future, we intend to continue the use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services.

Glossary of Oil and Natural Gas Terms

The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.

bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

bcf. Billion cubic feet of natural gas.

boe. Barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

boe/d. boe per day.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

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

Drilling locations. Total gross locations specifically quantified by management to be included in the Company’s multi-year drilling activities on existing acreage. The Company’s actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

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

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

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Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. An identifiable layer of rocks named after its geographical location and dominant rock type.

Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.

Leasehold. Mineral rights leased in a certain area to form a project area.

mbbls. Thousand barrels of crude oil or other liquid hydrocarbons.

mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids

mcf. Thousand cubic feet of natural gas.

mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

mmbbls. Million barrels of crude oil or other liquid hydrocarbons.

mmboe. Million barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

mmbtu. Million British Thermal Units.

mmcf. Million cubic feet of natural gas.

Net acres, net wells, or net reserves. The sum of the fractional working interest owned in gross acres, gross wells, or gross reserves, as the case may be.

Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues (PV-10). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such a general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

PV-10. Pre–tax present value of estimated future net revenues discounted at 10%.

Production. Natural resources, such as oil or gas, taken out of the ground.

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Productive well. A well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Project. A targeted development area where it is probable that commercial gas can be produced from new wells.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

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

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable from known reservoirs under current economic and operating conditions, operating methods, and government regulations.

Proved undeveloped reserves. 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 for recompletion.

Recompletion. The process of re-entering an existing well bore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reserves. Oil, natural gas and gas liquids thought to be accumulated in known reservoirs.

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

Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.

Shut-in. A well that has been capped (having the valves locked shut) for an undetermined amount of time. This could be for additional testing, could be to wait for pipeline or processing facility, or a number of other reasons.

Standardized measure. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Successful. A well is determined to be successful if it is producing oil or natural gas, or awaiting hookup, but not abandoned or plugged.

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

Water flood. A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

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Item 1A.

RISK FACTORS

CAUTIONARY STATEMENT REGARDING FUTURE RESULTS, FORWARD-LOOKING

INFORMATION AND CERTAIN IMPORTANT FACTORS

In this report we make, and from time to time we otherwise make, written and oral statements regarding our business and prospects, such as projections of future performance, statements of management’s plans and objectives, forecasts of market trends, and other matters that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements containing the words or phrases “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimates,” “projects,” “believes,” “expects,” “anticipates,” “intends,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions identify forward-looking statements, which may appear in documents, reports, filings with the Securities and Exchange Commission, news releases, written or oral presentations made by officers or other of our representatives to analysts, stockholders, investors, news organizations and others, and discussions with management and other of our representatives. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.

Our future results, including results related to forward-looking statements, involve a number of risks and uncertainties. No assurance can be given that the results reflected in any forward-looking statements will be achieved. Any forward-looking statement speaks only as of the date on which such statement is made. Our forward-looking statements are based upon assumptions that are sometimes based upon estimates, data, communications and other information from operators, government agencies and other sources that may be subject to revision. Except as required by law, we do not undertake any obligation to update or keep current either (i) any forward-looking statement to reflect events or circumstances arising after the date of such statement, or (ii) the important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or which are reflected from time to time in any forward-looking statement.

In addition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors, include the following:

Risks Related to our Company

We will require additional capital in order to achieve commercial success and, if necessary, to finance future losses from operations as we endeavor to build revenue, but we do not have any commitments to obtain such capital and we cannot assure you that we will be able to obtain adequate capital as and when required. The business of oil and gas acquisition, drilling and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. We believe that our ability to achieve commercial success and our continued growth will be dependent on our continued access to capital either through the additional sale of our equity or debt securities, bank lines of credit, project financing or cash generated from oil and gas operations.

As of December 31, 2007, we had working capital of $5.0 million, including $15.3 million of cash and cash equivalents. In addition, we have available to us a $75 million credit facility, of which $14.3 million is outstanding as of December 31, 2007, for purposes of financing our commitments towards the drilling and development of our most significant prospect, the Williston Basin properties. Based on our present working capital, available borrowings under the credit facility and current rate of cash flow from operations, we believe we have available to us sufficient working capital to fund our operations and expected commitments for exploration and development through, at least, December 31, 2008. However, in the event we receive calls for capital greater than, or generate cash flow from operations less than, we expect, we may require additional working capital to fund our operations and expected commitments for exploration and development prior to December 31, 2008. In addition, we are required to redeem our outstanding Series A Preferred Stock at a redemption price equal to the aggregate stated value plus any accrued and unpaid dividends, no later than October 2, 2008. Unless we are able to refinance the Series A Preferred Stock using our equity, we will need to raise additional capital in order to effect a cash redemption of the preferred shares.

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We will seek to obtain additional working capital through the sale of our securities and, subject to the successful deployment of our cash on hand, we will endeavor to obtain additional capital through bank lines of credit and project financing. However, other than our existing credit facility, we have no agreements or understandings with any third parties at this time for our receipt of additional working capital and we have no history of generating significant cash from oil and gas operations. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price will be materially adversely affected.

We do not have a significant operating history and, as a result, there is a limited amount of information about us on which to make an investment decision. We were incorporated in June 1997 to engage in the design and manufacturing of children’s apparel. We terminated that business line in 1999 and since then have been engaged in the pursuit of alternative lines of business. In late 2004, we began to focus our attention on oil and gas exploration and development in the United States. In April 2005, we commenced assembling our present management team. In July 2005, we acquired our initial exploratory drilling prospects and commenced drilling activities in November 2005. In December 2005, we commenced production from our first oil and gas prospects and received our first revenues from oil and gas production in February 2006. In February 2007 we acquired a 43% average working interest in 15 producing oil fields and approximately 150 producing wells located in the Williston Basin in North Dakota at which point we began to receive revenue from associated oil and gas production. Accordingly, there is little operating history upon which to judge our business strategy, our management team or our current operations.

We have a history of losses and cannot assure you that we will be profitable in the foreseeable future. Since we entered the oil and gas business in April 2005, through December 31, 2007, we have incurred a net loss from operations of $9,852,162. If we fail to generate profits from our operations, we will not be able to sustain our business. We may never report profitable operations or generate sufficient revenue to maintain our company as a going concern.

We do not act as an operator, which means we are dependent on third parties for the exploration, development and production of our leasehold interests. An oil and gas operator is the party that takes primary responsibility for management of the day-to-day exploration, development and production activity relating to an oil and gas prospect. Our business plan is to acquire working interests in oil and gas properties with an industry partner functioning as the operator. To date, we have entered into agreements with various oil and gas operators on a project-by-project basis and we have no long term agreements with any operators that ensure us of their services as we may need them. Our reliance on third party operators for the exploration, development and production of our property interests subjects us to a number of risks, including:

·		the possibility that our inability to act as an operator may limit our ability to bid on and acquire desirable leasehold interests;
·		the possibility that quality operators may not be available to us as and when needed;
·		our inability to control the amount and timing of costs and expenses of exploration, development and production; and
·		the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.

If we are unable to enter into suitable partnering arrangements with quality operators on a timely basis, we risk suffering a number of adverse consequences, including:

·		the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests;
·		loss of reputation in the oil and gas community;
·		a general slow down in our operations and decline in revenue; and
·		decline in market price of our common shares.

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We have limited management and staff and will be dependent for the foreseeable future upon consultants and partnering arrangements. At of March 2008, we have seven employees, including our five executive officers. We have developed an operating strategy that is based on our participation in producing properties and exploration prospects as a non-operator for the foreseeable future. We intend to use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We will also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:

·		the possibility that such third parties may not be available to us as and when needed; and

·		the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.

If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price will be materially adversely affected.

The loss of any of our executive officers could adversely affect us. We currently only have seven employees, including our five executive officers. We are dependent on the extensive experience of our executive officers to implement our acquisition and growth strategy. The loss of the services of any of our executive officers could have a negative impact on our operations and our ability to implement our strategy.

In addition to acquiring producing properties, we intend to also grow our business through the acquisition and development of exploratory oil and gas prospects, which is the riskiest method of establishing oil and gas reserves. In addition to acquiring producing properties, we intend to acquire, drill and develop exploratory oil and gas prospects that are profitable to produce. Developing exploratory oil and gas properties requires significant capital expenditures and involves a high degree of financial risk. The budgeted costs of drilling, completing, and operating exploratory wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an exploratory oil or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. We cannot assure you that our exploration, exploitation and development activities will result in profitable operations. If we are unable to successfully acquire and develop exploratory oil and gas prospects, our results of operations, financial condition and stock price will be materially adversely affected.

Hedging transactions may limit our potential gains or result in losses. In order to manage our exposure to price risks in the marketing of our oil and natural gas, from time to time we enter into oil and gas price hedging arrangements with respect to a portion of our proved developed producing production. While these contracts are intended to reduce the effects of volatile oil and natural gas prices, they may also limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

·		there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;
·		our production and/or sales of oil or natural gas are less than expected;
·		payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
·		the other party to the hedging contract defaults on its contract obligations.

We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.

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Any failure to meet our debt obligations would adversely affect our business and financial condition. In conjunction with our acquisition of the producing properties in North Dakota, PRC Williston LLC, our wholly-owned subsidiary, entered into a $75 million credit agreement on February 16, 2007, of which approximately $14.3 million was outstanding as of December 31, 2007. Funds borrowed under the new credit facility bear interest at a rate equal to (x) the greater of the prime rate or 7.5%, plus (y) 2%, with interest payable monthly. The principal amount of advances outstanding under the credit facility are repayable monthly in an amount approximating 100% of PRC Williston’s cash on hand (from any source) less all permitted costs and expenses paid by PRC Williston for the monthly period.

PRC Williston’s ability to meet its debt obligations under the credit agreement will depend on the future performance of the North Dakota properties, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. PRC Williston’s failure to service its debt could result in a default under the credit agreement, which could materially adversely affect our business, financial condition and results of operations.

We have guaranteed the performance of PRC Williston’s obligations under the credit facility and have secured our guarantee by granting to the lenders a first priority security interest in our ownership interest in PRC Williston. If PRC Williston’s cash flow is not sufficient to service its debt, we may be required to perform our obligations under the guarantee which could have a negative impact on our ability to fund our other operations and we may be required to refinance the debt, sell assets or sell additional shares of common stock on terms that we do not find attractive.

The credit agreement obligates PRC Williston to comply with certain financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio beginning with the quarter ending on June 30, 2007, a minimum interest coverage ratio and debt coverage ratios based on earnings and petroleum reserves, as such ratios are defined in the agreement. Subsequent to June 30, 2007, PRC Williston entered into agreements with the lenders to postpone the calculation of the financial covenants and waive various financial covenants until the quarter ended December 31, 2007. There can be no assurance that we will be able to meet the financial covenants, and if we fail to satisfy or obtain waivers for these covenants, we would be subject to the default provisions of the agreement, which could materially adversely affect our business, financial condition and results of operations.

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If we are unable to fund our commitment to Hall-Houston Exploration II, L.P., we may be forced to sell our entire investment in the fund at a significant loss. Pursuant to the limited partnership agreement, we are required to fund our $8.0 million in the partnership based on calls for capital made by the general partner from time to time. The general partner is authorized to issue a call for capital contributions at any time, and from time to time, over a three year period expiring in April 2009. In the event we are unable or unwilling to fund a capital call, the general partner may, among other actions, require us to sell our entire limited partnership interest to the other limited partners or the partnership, at the option of the other limited partners and the partnership, at a price equal to the lower of (i) 75% of the fair market value of our interest and (ii) 75% of our capital account balance in the partnership. As of March 15, 2008, we have funded $3.9 million of our $8.0 million commitment. The general partner is unable to predict the timing and amount of the future calls for capital. If we are unable to fund a capital call when made, we may be forced to sell our entire investment in the partnership at a significant loss, in addition to being held liable for other damages to the partnership resulting from our breach of the partnership agreement.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations. Significant growth in the size and scope of our operations could place a strain on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plans.

Unless we replace our oil and gas reserves, our reserves and production will decline, which would materially and adversely affect our business, financial condition and results of operations. Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Thus, our future oil and gas reserves and production and, therefore, our cash flow and revenue are highly dependent on our success in efficiently developing our current reserves and acquiring additional recoverable reserves. We may not be able to develop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would be materially and adversely affected.

The unavailability or high cost of drilling rigs, equipment supplies or personnel could adversely affect our ability to execute our exploration and development plans. The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies my increase substantially and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. The higher prices of oil and gas during the last several years have resulted in shortages of drilling rigs, equipment and personnel, which have resulted in increased costs and shortages of equipment in program areas we operate. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our financial condition and results of operations could be materially and adversely affected.

Covenants in our credit facility impose significant restrictions and requirements on us. Our credit facility contains a number of covenants imposing significant restrictions on us, including restrictions on our repurchase of, and payment of dividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets and create liens on our assets. These restrictions may affect our ability to operate our business, to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial conditions and results of operations.

Our credit facility also requires our operating subsidiaries to achieve and maintain certain financial ratio tests. There can be no assurance that our operating subsidiaries will be able to achieve and maintain compliance with these prescribed financial ratio tests or other requirements under our credit facility. Failure to achieve or maintain compliance with the financial ratio tests or other requirements under our credit facility would result in a default and could lead to the acceleration of our obligations under our credit facility.

A substantial portion of the assets of our operating subsidiaries are pledged to secure the obligations under our credit facility. Our lack of unencumbered collateral could materially and adversely affect our ability to obtain, or increase the cost of obtaining, additional financing in the future.

[20]

Lack of pipeline access, gathering systems and other production equipment may hinder our access to oil and gas markets or delay our production. The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. For example, there are no gathering systems in some of the program areas where we have acreage. Therefore, if drilling results are positive in these program areas, new gathering systems would need to be built to deliver any gas production to markets. There can be no assurance that we would have sufficient liquidity to build such systems or that third parties would build systems that would allow for the economic development of any such production.

We deliver our production through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future. Our ability to produce and market our production is affected and also may be harmed by:

·		the lack of pipeline transmission facilities or carrying capacity;
·		federal and state regulation of oil and gas production; and
·		federal and state transportation, tax and energy policies.

Any significant change in our arrangement with gathering system or pipeline owners and operators, or other market factors affecting the overall infrastructure facilities servicing our properties, could adversely impact our ability to deliver the oil and gas that we produce to markets in an efficient manner or the prices we receive. In some cases, we may be required to shut in wells, at least temporarily, for lack of a market because of the inadequacy or unavailability of transportation facilities. If that were to occur, we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.

We are exposed to operating hazards and uninsured risks. Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

·		fire, explosions and blowouts;
·		pipe failure;
·		abnormally pressured formations; and
·		environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).

These events may result in substantial losses to us from:

·		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;
·		penalties and suspension of operations; or
·		attorney's fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in our industry, we maintain insurance against some, but not all, of these risks. We cannot assure you that our insurance will be adequate to cover these losses or liabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations.

We carry well control insurance for our drilling operations. Our coverage includes blowout protection and liability protection on domestic and international wells.

The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions and weather conditions. These curtailments can last from a few days to many months.

[21]

Risks Relating to the Oil and Gas Industry

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our capital expenditure obligations and financial commitments and to implement our business strategy. Oil and natural gas are commodities and are subject to wide price fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:

·		changes in global supply and demand for oil and natural gas;
·		the actions of the Organization of Petroleum Exporting Countries, or OPEC;
·		the price and quantity of imports of foreign oil and natural gas;
·		acts of war or terrorism;
·		political conditions and events, including embargoes, affecting oil-producing activity;
·		the level of global oil and natural gas exploration and production activity;
·		the level of global oil and natural gas inventories;
·		weather conditions;
·		technological advances affecting energy consumption;
·		the price and availability of alternative fuels; and
·		market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but may also reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Our industry is highly competitive which may adversely affect our performance, including our ability to participate in ready to drill prospects in our core areas. We operate in a highly competitive environment. In addition to capital, the principal resources necessary for the exploration and production of oil and natural gas are:

·		leasehold prospects under which oil and natural gas reserves may be discovered;
·		drilling rigs and related equipment to explore for such reserves; and
·		knowledgeable personnel to conduct all phases of oil and natural gas operations.

We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these competitors have financial and other resources substantially greater than ours. We cannot assure you that such materials and resources will be available when needed. If we are unable to access material and resources when needed, we risk suffering a number of adverse consequences, including:

·		the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests;
·		loss of reputation in the oil and gas community;
·		a general slow down in our operations and decline in revenue; and
·		decline in market price of our common shares.

[22]

Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of reserves shown in these reports.

In order to prepare reserve estimates in its reports, our independent petroleum consultant projected production rates and timing of development expenditures. Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary and may not be in our control. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Prospects that we decide in which to participate may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return. A prospect is a property in which we own an interest and have what we believe, based on available seismic and geological information, to be indications of oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion cost or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analysis we perform using data from other wells, more fully explored prospects and/or producing fields will be useful in predicting the characteristics and potential reserves associated with our drilling prospects.

We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business. Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, and operating safety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may result in substantial penalties and harm to our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:

[23]

land use restrictions;

lease permit restrictions;

drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds;

spacing of wells;

unitization and pooling of properties;

safety precautions;

operational reporting; and

taxation.

Under these laws and regulations, we could be liable for:

personal injuries;

property and natural resource damages;

well reclamation cost; and

governmental sanctions, such as fines and penalties.

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is also possible that a portion of our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See Item 1 “Business—Government Regulations” for a more detailed description of our regulatory risks.

Our operations may incur substantial expenses and resulting liabilities from compliance with environmental laws and regulations. Our oil and natural gas 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 environmental protection. These laws and regulations:

require the acquisition of 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.

Failure to comply with these laws and regulations may result in:

the assessment of administrative, civil and criminal penalties;

incurrence of investigatory or remedial obligations; and

the imposition of injuctive relief.

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 reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Our permits require that we report any incidents that cause or could cause environmental damages. See Item 1 “Business—Government Regulations” for a more detailed description of our environmental risks.

[24]

Risks Relating to our Common Stock

The market for our stock is limited and may not provide investors with either liquidity or a market based valuation of our common stock. Our common stock is traded on the American Stock Exchange market under the symbol “PRC”. As of March 29, 2008, the last reported sale price of our common stock on the AMEX was $1.35 per share. However, we consider our common stock to be “thinly traded” and any last reported sale prices may not be a true market-based valuation of the common stock. Also, the present volume of trading in our common stock may not provide investors sufficient liquidity in the event they wish to sell their common shares. There can be no assurance that an active market for our common stock will develop. In addition, the stock market in general, and early stage public companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of such companies. If we are unable to develop a market for our common shares, you may not be able to sell your common shares at prices you consider to be fair or at times that are convenient for you, or at all.

The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock in the public markets and the issuance of shares of common stock in future acquisitions. Sales of a substantial number of shares of our common stock by us or by other parties in the public market or the perception that such sales may occur could cause the market price of our common stock to decline. In addition, the sale of such shares in the public market could impair our ability to raise capital through the sale of common or preferred stock.

In addition, in the future, we may issue shares of our common stock in furtherance of our acquisitions and development of assets or businesses. If we use our shares for this purpose, the issuances could have a dilutive effect on the value of your shares, depending on market conditions at the time of an acquisition, the price we pay, the value of the assets or business acquired and our success in exploiting the properties or integrating the businesses we acquire and other factors.

Item 1B.

UNRESOLVED STAFF COMMENTS

None.

Item 2.

PROPERTIES

Company Location and Facilities

Our executive offices are located at 777 Post Oak Boulevard, Suite 910 in Houston, Texas. We entered into a five year lease beginning May 1, 2007 covering approximately 2,900 square feet and the current monthly base rental is $4,827 with the base rental escalating to a monthly base rate of $5,430 in 2011.

Reserves

Our natural gas and crude oil reserves have been estimated as of December 31, 2007 by Cawley, Gillespie & Associates, Inc. and DeGolyer & MacNaughton. Natural gas and crude oil reserves, and the estimates of the present value of future net revenues therefrom, were determined based on then current prices and costs.

There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserve quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.

[25]

The following table sets forth our estimated proved reserves as of December 31, 2007.

	Proved Reserves
	2007						2006
	Developed		Undeveloped		Total		Developed		Undeveloped		Total
Crude Oil (bbls):
CGA		1,379,330		604,865		1,984,195		7,900		-		7,900
DM		143,288		242,117		385,405		-		-		-
Total Oil (bbls):		1,522,618		846,982		2,369,600		7,900		0		7,900
Natural Gas (Boe)
CGA		132,102		-		132,102		6,833		12,516		19,349
DM		78,119		136,781		214,900		-		-		-
Total Gas (Boe):		210,221		136,781		347,002		6,833		12,516		19,349
Total Proved Reserves (Boe)		1,732,839		983,763		2,716,602		14,733		12,516		27,249

Production, Average Sales Prices and Average Costs of Production

The following table sets forth certain information regarding production volumes, average sales prices and average costs of production, including depletion, depreciation and allowance, or DD&A for the three years ended December 31, 2007.

	2007	2006	2005*
Production Volume
Natural Gas (Mcf)	151,627	20,266	--
Oil and Natural Gas Liquids (Bbls)	99,417	67	--
Average Sales Prices:			--
Natural Gas (per Mcf)	$ 3.49	$ 5.89	--
Oil (Bbls)	$ 64.28	$ 54.62	--
Costs of Production (per Bbl)	$ 28.16	$ 13.81	--
DD&A (per Bbl)	$ 14.29	$ 76.19	--

______________

* We had insignificant natural gas production and no oil production attributable to our working interests during the year ended December 31, 2005.

[26]

Drilling Activity

Information with regard to our drilling activities during the three years ended December 31, 2007 is set forth below.

	2007		2006		2005
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells:
Productive	15	2.11	9	1	3	0.2
Unproductive	6	0.93	12	2.1	1	0.1
Total	21	3.04	21	3.1	4	0.3
Developmental Wells:	4	1.96	0	0	0	0
Total Wells:
Productive	19	4.07	9	1	3	0.2
Unproductive	6	0.93	12	2.1	1	0.1
Total	25	5	21	3.1	4	0.3

Acreage

The following table summarizes by state our developed and undeveloped acreage as of December 31, 2007. The term of the undeveloped leasehold acreage ranges from three to five years.

	Developed1				Undeveloped2
State	Gross3		NET4		Gross3		NET4
North Dakota		15,200		6,393		3,411		1,116
Texas		2,457		229		43,800		7,600
Louisiana		640		64		-		-
Kentucky		-		-		74,000		4,936
Utah		-		-		20,300		17,249
New Mexico		-		-		90,000		9,000
Colorado		-		-		9,315		1,747
Totals		18,297		6,686		240,826		41,648

Productive Wells

The following table summarizes by geographic area our gross and net interests in producing oil and gas wells as of December 31, 2007. Productive wells are producing wells and wells capable of production, including gas wells awaiting pipeline connections and oil wells awaiting connection to production facilities. Wells that are dually completed in more than one producing horizon are counted as one well.

_________________

1 Developed acreage is acreage spaced for or assignable to productive wells.

2 Undeveloped acreage is oil and gas acreage on which wells have not been drilled or to which no proved reserves other than proved undeveloped reserves have been attributed.

3 A gross well or acre is a well or acre in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

4 A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions thereof.

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	Gross Wells2				Net Wells3
State	Oil		Gas		Oil		Gas
North Dakota		140		0		60.9		0
Texas		9		9		0.9		.875
Louisiana		0		1		0		0.1
Total		149		10		61.8		.975

Our oil and natural gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, natural gas leaks, ruptures and discharges of toxic gases. In addition, title problems, weather conditions and mechanical difficulties or shortages or delays in delivery of drilling rigs and other equipment could negatively affect our operations. If any of these or other similar industry operating risks occur, we could have substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with industry practice, we have obtained insurance against some, but not all, of the risks described above. However, we cannot assure you that the insurance obtained by us will be adequate to cover any losses or liabilities.

Present Activities

For additional information concerning our estimated proved reserves, the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2007 and 2006, and the changes in quantities and standardized measure of such reserves for each of the two years then ended, see Note 15 to our financial statements.

For a description of our present oil and gas operational activities, please see “Principal Oil and Gas Interests” in Part I, Item 1 of this report.

Item 3.

LEGAL PROCEEDINGS

There are no pending legal proceedings to which we or our properties are subject.

Item 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

_________________

2 A gross well or acre is a well or acre in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

3 A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions thereof.

[28]

PART II

Item 5.

MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Recent Market Prices

Our common stock has traded on the American Stock Exchange since August 28, 2006 under the symbol “PRC.” Prior to certification for listing on the American Stock Exchange, our common shares were traded on the electronic pink sheets section of OTC market.

The following table shows the high and low sales prices of our common stock for the periods indicated.

	High		Low
2007:
First quarter	$	3.66	$	2.21
Second quarter		3.14		2.30
Third quarter		2.95		1.96
Fourth quarter		2.55		1.75

2006:
First quarter	$	5.75	$	3.25
Second quarter		7.00		3.35
Third quarter		5.50		3.00
Fourth quarter		3.20		2.40

On March 29, 2007, there were approximately 211 owners of record of our common stock. We have not paid any cash dividends since our inception and do not contemplate paying dividends in the foreseeable future. It is anticipated that earnings, if any, will be retained for the operation of our business.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information with respect to our common shares issuable under our equity compensation plans as of December 31, 2007:

	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 Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c)
Equity compensation plans approved by security holders		1,125,000	$	3.67		1,775,000
Equity compensation plans not approved by security holders		0		0		0
Total		1,125,000	$	3.67		1,775,000

[29]

Recent Sales of Unregistered Securities

We have previously disclosed by way of quarterly reports on Form 10-QSB and current reports on Form 8-K filed with the SEC all sales by us of our unregistered securities during 2007.

Item 6.

SELECTED FINANCIAL DATA

Not applicable.

[30]

Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with our financial statements included elsewhere in this Form 10-K. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors including those set forth in our “Risk Factors” described herein.

General

We are an independent oil and natural gas company engaged in the acquisition, drilling and production of oil and natural gas properties in the United States. We act as a non-operator, which means we do not directly manage exploration, drilling or development operations. Instead, we pursue interests in oil and gas properties in partnership with oil and gas companies that have exploration, development and production expertise. It is our intention to pursue the acquisition of oil and gas properties principally in the Gulf of Mexico, Texas, New Mexico, North Dakota, Louisiana and Kentucky.

Since commencement of our domestic oil and natural gas operations in July 2005, we have been engaged in the acquisition of leases and raising capital with which to fund lease acquisition, exploration and development. In July 2005, we acquired our initial interest in oil and natural gas prospects and commenced drilling activities in November 2005. In December 2005, we commenced production operations from our first oil and natural gas prospects and received our first revenues from oil and natural gas production in February 2006. In April 2006, in order to establish a presence in the Gulf of Mexico, we purchased a 5.3% limited partner interest in Hall-Houston Exploration II, L. P., an oil and natural gas exploration and development partnership that has operations focused primarily offshore in the Gulf of Mexico. In February 2007, we acquired an approximately 43% average working interest in 15 producing oil fields and approximately 150 producing wells located in the Williston Basin of North Dakota.

As of December 31, 2006, our net total proved reserves were approximately 27,249 boe of which 7,900 boe were crude oil reserves. As of December 31, 2007, our estimated net total proved reserves had grown to approximately 2,716,602 boe (net of production) of which approximately 2,369,600 boe were crude oil reserves and 347,002 boe were natural gas reserves. The increase in net total proved reserves is a result of our Williston Basin Acquisition that closed on February 16, 2007, positive results from enhanced oil recovery operations in North Dakota, and successful exploratory drilling success in our Williston Basin Joint venture and in our Cinco Terry Project in Crockett County, Texas.

Results of Operations

Our operating strategy is to participate as a non-operator in oil and natural gas properties and prospects. Our plan of operations is to acquire domestic oil and natural gas interests and obtain the additional working capital necessary to pay our share of the costs to explore, develop or enhance the production from such properties. In July 2005, we acquired our initial interest in drilling prospects and commenced drilling activities in November 2005. In December 2005, we commenced production operations from our first oil and natural gas prospects and received our first revenues from oil and natural gas production in February 2006. In April 2006, we acquired our limited partnership interest in Hall-Houston exploration II, L.P. in order to establish a presence in the Gulf of Mexico. In February 2007, we acquired existing production in North Dakota which significantly increased our oil reserves, leasehold acreage position and monthly revenues.

For the Year Ended December 31, 2007 Compared to December 31, 2006

Revenues for the year ended December 31, 2007 totaled $7,020,533 compared to revenues of $1,546,170 for the year ended December 31, 2006. Revenue for the year ended December 31, 2007 consisted $6,920,533 of oil and gas sales, whereas revenue for the prior year period consisted of $151,416 of oil and gas sales and $1,394,754 of revenue from the gain on our sale of an undivided interest in the Palo Duro Basin acreage for cash consideration of approximately $3,950,000. The increase in revenue from oil and gas sales was due primarily to our acquisition of the interest in the Williston Basin properties in the first quarter of 2007 and our successful exploratory drilling results in North Dakota and Crockett County, Texas. We generated $6.4 million of revenue from oil and gas sales from our interest in the Williston Basin properties from the acquisition date (February 16, 2007) through December 31, 2007. During the first quarter of 2007, we also generated $100,000 of revenue representing a liquidated damage penalty for failure to commence drilling by a specified date assessed against our operating partner in the Palo Duro acreage.

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Lease operating expenses for the year ended December 31, 2007 totaled $3,510,521, compared to lease operating expenses of $55,172 for the prior year period. The increase in lease operating expenses was due primarily to our acquired interest in the Williston Basin properties and to the increase in the number of producing wells in our Cinco Terry Field in Crockett County, Texas.

Exploration costs declined to $1,767,898 for the year ended December 31, 2007 from $2,150,729 during the prior year period. Exploration costs represent our drilling costs associated with dry holes. The decline in exploration costs is the result of a decrease in the number of dry holes drilled as a percentage of all exploratory drilling.

Our expenses for impairment of oil and gas properties declined to $95,272 in the year ended December 31, 2007 from $614,770 during the prior year period. Impairment expenses represent the write-down of previously capitalized expenses for productive wells. We take an impairment charge for a productive well when there is an indication that we may not receive production payments equal to the net capitalized costs. The decline in expenses for impairment of oil and gas properties is the result of a fewer number of wells needing to be written down which is in part due to higher oil and gas prices.

Our expenses for depreciation, depletion, and accretion for the year ended December 31, 2007 totaled $1,781,263, compared to $304,396 for the prior year period. This was due to an increase in capitalized costs and increased production as a result of our acquisition of the Williston Basin properties and the Cinco Terry Field drilling program.

General and administrative expenses for the year ended December 31, 2007 totaled $2,751,647 compared to general and administrative expenses of $2,602,632 for the prior year period. General and administrative expenses for the years ended December 31, 2007 and December 31, 2006 included expenses of $1,117,836 and $1,598,541, respectively, for outstanding common stock options granted under our Stock Incentive Plan and common shares issued to an executive officer in the second quarter of 2007. Without giving effect to expenses for common shares and stock options, our general and administrative expenses for the years ended December 31, 2007 and December 31, 2006 were $1,633,811 and $1,004,091, respectively. The increase in general and administrative expenses (other than expenses for options and common shares) between reporting periods was due to increased number of employees, additional office space, professional fees, travel and other expenses related to our purchase of the Williston Basin properties.

We incurred a net loss from operations of $2,886,068 for the 2007 fiscal year, compared to a net loss from operations of $4,181,529 during the prior year. However, we generated positive cash flow from operations of $853,615 in fiscal 2007, compared to a negative cash flow from operations of $754,809 for fiscal 2006. The net loss from operations decreased during 2007 due to the decreased expenses associated with exploration and impairment, offset by the increased depreciation, depletion and accretion. Overall, however, our cash flow from operations in fiscal 2007 increased by approximately $1,608,424 over fiscal 2006 due to the profitable exploration and drilling operations in the Williston Basin and Cinco Terry properties.

During the year ended December 31, 2007, interest expense increased by $739,003 to $743,023, over the prior year period. The increase in interest expense was principally due to our credit facility pursuant to which we partially financed our acquisition of the Williston Basin properties.

During the year ended December 31, 2007, we incurred a loss on derivative contracts of $2,458,165. Beginning in March 2007, we have entered into commodity derivative financial instruments for purposes of hedging our exposure to market fluctuations of oil prices. Our loss on derivative contracts include both $625,849 in losses on the actual settlement of certain derivative financial instruments during year ended December 31, 2007 and the unrealized loss of $1,832,316 based on the changes in the fair value of derivative instruments covering positions beyond December 31, 2007. These fluctuations are driven by change in the market prices of hedged oil and gas volumes.

[32]

During the year ended December 31, 2007, we paid dividends on our Series A Preferred Stock in the form of additional shares of our Series A Preferred Stock with a calculated value of $510,928 based on the stated value of $3 per share. As our Series A Preferred shares were issued in May 2007, there were no dividends paid in the prior year. The dividend payments are a non-cash expense because during 2007 we elected to pay all dividends in the form of additional share of our Series A Preferred Stock.

We incurred a net loss to common stockholders of $6,050,357 during fiscal 2007, compared to a net loss to common stockholders of $3,898,985 for the prior year period. The increase in net loss to common stockholders was primarily the result of an increase during 2007 in our loss on derivative contracts, interest expense and dividends payable, offset by a decrease in our net loss from operations of $1,429,996.

During the year ended, December 31, 2007, cash flow from operations totaled $853,615 which represents an increase of $1,608,424 from the same period in 2006. This increase was primarily due to greater production from the Williston Basin and the Cinco Terry Project.

Plan of Operations

Our plan of operations for the next twelve months is to pursue further exploration and development of the oil and natural gas prospects that we currently own, along with obtaining the working capital required to fund such exploration and development and the acquisition of additional domestic oil and natural gas interests in North Dakota, the Gulf of Mexico, Texas, Louisiana, New Mexico and Kentucky. We intend to pursue prospects in partnership with other companies with exploration, development and production expertise. We will also pursue alliances with unaffiliated third parties in the areas of geological and geophysical services and prospect generation, evaluation and leasing.

The business of oil and natural gas acquisition, exploration and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. Therefore, a principal part of our plan of operations is to raise the additional capital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties. As explained under “Financial Condition and Liquidity” below, based on our present working capital, available borrowings under the credit facility and current rate of cash flow from operations, we believe we have available to us sufficient working capital to fund our operations and expected commitments for exploration and development through, at least, December 31, 2008. However, in the event we receive calls for capital greater than, or generate cash flow from operations less than, we expect, we may require additional working capital to fund our operations and expected commitments for exploration and development prior to December 31, 2008. We will seek additional working capital through the sale of our securities and we will endeavor to obtain additional capital through bank lines of credit and project financing. However, as described further below, under the terms of our guarantee of a $75 million credit facility entered into by our subsidiary, PRC Williston, we are prohibited from incurring any additional debt from third parties. Our ability to obtain additional working capital through bank lines of credit and project financing may be subject to the repayment of the $75 million credit facility.

We intend to use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental, investor relations and tax services. We believe that by limiting our management and employee costs, we may be able to better control total costs and retain flexibility in terms of project management. Consequently, we do not expect any significant purchase or sale of plant or equipment, or significant change in the number of our employees, during the next twelve months.

[33]

Financial Condition and Liquidity

As of the date of this report, we estimate our capital budget for fiscal 2008 to be approximately $21.9 million, including:

	·	Up to $12.8 million of capital for secondary enhanced oil recovery operations and exploratory drilling in the Williston Basin.
	·	Up to $4.1 million to be called upon to fund our commitment to Hall-Houston Exploration II, L. P. As of the date of this report, we have funded $3.9 million of our $8.0 million commitment and have assumed that up to $4.1 million of our remaining commitment will be called for during the next 12 months.
	·	Up to $4.8 million to be deployed in connection with our interest in the Cinco Terry Project, El Vado East and Boomerang prospects operated by Approach Resources, Inc.

As of December 31, 2007, we had total assets of $66.3 million and working capital of $5.6 million. In addition, we have available to us a $75 million credit facility, of which $14.3 million is outstanding as of December 31, 2007, for purposes of financing our commitments towards the drilling and development of our most significant prospect, the Williston Basin properties. Based on our present working capital, available borrowings under the credit facility and current rate of cash flow from operations, we believe we have available to us sufficient working capital to fund our operations and expected commitments for exploration and development through, at least, December 31, 2008. However, in the event we receive calls for capital greater than, or generate cash flow from operations less than, we expect, we may require additional working capital to fund our operations and expected commitments for exploration and development prior to December 31, 2008. In addition, we are required to redeem our outstanding Series A Preferred Stock at a redemption price equal to the aggregate stated value of $7,232,329, plus any accrued and unpaid dividends, no later than October 2, 2008. Unless we are able to refinance the Series A Preferred Stock using our equity, we will need to raise additional capital in order to effect a cash redemption of the preferred shares.

We will seek to obtain additional working capital through the sale of our securities and, subject to the successful deployment of our cash on hand, we will endeavor to obtain additional capital through bank lines of credit and project financing. However, other than our existing $75 million credit facility, we have no agreements or understandings with any third parties at this time for our receipt of additional working capital and we have no history of generating significant cash from oil and gas operations. Further, as described further below, under the terms of our guarantee of the $75 million credit facility, we are prohibited from incurring any additional debt from third parties. Our ability to obtain additional working capital through bank lines of credit and project financing may be subject to the repayment of the $75 million credit facility. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price will be materially adversely affected.

PRC Williston Credit Facility

In connection with our acquisition of the Williston Basin properties, our wholly-owned subsidiary, PRC Williston LLC, entered into a $75 million credit agreement, pursuant to which, the lenders have initially agreed to loan PRC Williston $20.3 million for purposes of financing the acquisition of its interest in the Williston Basin fields, including certain transaction costs and fees, its costs of drilling and development of oil and natural gas properties, and general working capital. As of December 31, 2007, we owed a total of $14.3 million under the credit agreement. Any advances under the credit agreement are to be used to fund PRC Williston’s acquisition of additional oil and natural gas properties and costs of drilling and development, subject to certain conditions and the prior approval of the lenders.

All funds borrowed by PRC Williston under the credit agreement bear interest at the rate equal to (x) the greater of the prime rate or 7.5%, plus (y) 2%, with interest payable monthly. The principal amount of advances outstanding under the credit agreement are repayable monthly in an amount approximating 100% of PRC Williston’s cash on hand (from any source) less all permitted costs and expenses paid by PRC Williston for the monthly period. PRC Williston’s obligations under the credit agreement have been secured by its grant of a first priority security interest and mortgage on all of its assets. We have also guaranteed the performance of PRC Williston’s obligations under the credit agreement and related agreements and have secured our guarantee by granting to the lenders a first priority security interest in our ownership interest in PRC Williston LLC. In addition, our guarantee agreement with the lenders prohibits us from incurring any additional debt from third parties. Any demand on us to perform our obligations under the guarantee could have a negative impact on our ability to fund our other operations.

[34]

The credit agreement obligates PRC Williston to comply with certain financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio beginning with the quarter ending on June 30, 2007, a minimum interest coverage ratio and debt coverage ratios based on earnings and petroleum reserves, as such ratios are defined in the agreement. Subsequent to June 30, 2007, PRC Williston entered into agreements with the lenders to postpone the calculation of the financial covenants and waive various financial covenants until the quarter ended December 31, 2007. There can be no assurance that we will be able to meet the financial covenants, and if we fail to satisfy or obtain waivers for these covenants, we would be subject to the default provisions of the agreement. All of the assets of our operating subsidiary are pledged to secure the obligations under our credit facility. Our lack of unencumbered collateral could materially and adversely affect our ability to obtain, or increase the cost of obtaining, additional financing in the future.

Series A Preferred Stock Financing

On April 3, 2007, we completed the sale of 2,240,467 shares of our Series A Preferred Stock to two funds managed by Touradji Capital Management, LP (the “Touradji Funds”) in consideration of the Touradji Funds’(i) payment of $2 million; (ii) return of 1,537,800 shares of our common stock purchased in previous periods (“Consideration Shares”); and (iii) the return of 160,000 common stock purchase warrants (“Consideration Warrants”) with a deemed aggregate value of $4,721,400 (or $3.00 per common share).

In the first quarter of 2006, the Touradji Funds had participated in our 2006 private placement in which they purchased 400,000 units at $10 per unit. Each unit consisted of four shares of our common stock and one warrant to purchase an additional share of common stock at an exercise price of $3.00 per share over a five year period. The Consideration Shares and Consideration Warrants represent all common shares and 160,000 of the 400,000 warrants acquired by the Touradji Funds in the 2006 private placement, except for 62,200 common shares previously disposed of by the Touradji Funds.

Pursuant to a Certificate of Designations filed with the Delaware Secretary of State on March 30, 2007, the Series A Preferred Stock is issued at a stated value of $3.00 per share (“Stated Value”) and is convertible into shares of our common stock at any time at a conversion price of $4.50 per share. Both the Stated Value and conversion price are subject to adjustment in the event of any stock splits, dividends, combinations or the like affecting the Series A Preferred Stock or common stock, or any fundamental transactions. Each share of Series A Preferred Stock is entitled to dividends on the Stated Value at the rate of 10% per annum, provided that the dividend rate shall increase to 15% on April 3, 2008. Dividends are payable quarterly in cash or, at our option, in shares of Series A Preferred Stock at the Stated Value. The Series A Preferred Stock is entitled to vote with the common stock on an as converted basis. In the event of the liquidation of our company, each outstanding share of Series A Preferred Stock shall be entitled to a liquidation payment in the amount equal to the greater of (x) the Stated Value, plus any accrued and unpaid dividends, and (y) the amount payable per share of common stock which a holder of Series A Preferred Stock would have received if such holder had converted to common stock immediately prior to the liquidation event, plus any accrued and unpaid dividends. We are required to redeem all outstanding shares of Series A Preferred Stock on October 2, 2008 at a redemption price equal to the Stated Value, plus any accrued and unpaid dividends. We have the option to redeem the Series A Preferred Stock at any time, subject to 30 days prior written notice, at the same redemption price.

[35]

To date, we have elected to pay all dividends in the form of additional shares of Series A Preferred Stock in lieu of cash. As of March 31, 2008, we have issued an additional 230,580 shares of Series A Preferred Stock as dividends.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet financing arrangements.

Item 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

[36]

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-1

Balance Sheets at December 31, 2007 and 2006	F-2

Statements of Operations for the years ended December 31, 2007 and 2006	F-3

Statements of Shareholders' Equity for the years ended December 31, 2007 and 2006	F-4

Statements of Cash Flows for the years ended December 31, 2007 and 2006	F-5

Notes to Financial Statements	F-6

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors

Petro Resources Corporation

Houston, Texas

We have audited the accompanying consolidated balance sheets of Petro Resources Corporation (the "Company") as of December 31, 2007 and 2006, and the related consolidated statements of operations, shareholders' equity, and cash flows for the years then ended. 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 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 an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opin

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Petro Resources Corporation as of December 31, 2007 and 2006, and the results of operations and cash flows for the two years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ MALONE & BAILEY, PC

www.malone-bailey.com

Houston, Texas

March 31, 2008

F-1

PETRO RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,			December 31,
	2007			2006
Assets
Current assets
Cash and cash equivalents	$	15,399,547		$	4,285,204
Accounts receivable		924,607			91,344
Prepaids		25,519			11,602
Deferred financing costs, net of amortization of $1,513,586		2,378,492			-
Total current assets		18,728,165			4,388,150


Property and equipment
Oil and natural gas properties, successful efforts accounting
Unproved		24,676,434			3,728,112
Proved properties, net		18,936,428			527,958
Furniture and fixtures, net		118,354			-
Total property and equipment		43,731,216			4,256,070

Other assets
Investment in partnership		3,892,944			2,293,104
Deposit		10,257			10,257
Total other assets		3,903,201			2,303,361

Total Assets	$	66,362,582		$	10,947,581

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable	$	1,525,474		$	216,870
Accrued liabilities		210,351			1,300
Stock payable		34,068			-
Short-term debt, net of discount of $2,956,206		11,344,136			-
Total current liabilities		13,114,029			218,170

Market value of derivatives		1,832,316			-
Asset retirement obligation		1,434,114			30,653
Total liabilities		16,380,459			248,823

Minority interest		3,025,375			-

Redeemable Preferred Stock
Series A Convertible Preferred Stock,$3 stated value, issued 2,410,776 shares; cumulative, dividend rate 10% per annum with liquidation preferences		7,232,329			-

Shareholders' equity
Preferred stock, $0.01 par value; 10,000,000 shares authorized, 2,410,776 shares of Series A Preferred Stock issued and outstanding as of December 31, 2007 (reported above)		-			-

Common stock, $0.01 par value; 100,000,000 shares authorized, 36,599,372 and 19,677,317 shares issued and outstanding as of December 31, 2007 and December 31, 2006 respectively		365,994			196,773
Additional paid in capital		49,723,515			14,816,718
Accumulated deficit		(10,365,090	)		(4,314,733	)
Total shareholders' equity		39,724,419			10,698,758

Total Liabilities and Shareholders' Equity	$	66,362,582		$	10,947,581

The accompanying notes are an integral part of these financial statements.

F-2

PETRO RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended
	December 31
	2007			2006
Revenue
Oil and gas sales	$	6,920,533		$	151,416
Other income		100,000			-
Gain (loss) on sale of property		-			1,394,754
		7,020,533			1,546,170
Expenses
Lease operating expenses		3,510,521			55,172
Exploration		1,767,898			2,150,729
Impairment of oil & gas properties		95,272			614,770
Depreciation, depletion and accretion		1,781,263			304,396
General and administrative		2,751,647			2,602,632

Total expenses		9,906,601			5,727,699

Loss from operations		(2,886,068	)		(4,181,529	)

Other income and (expense)
Interest income		171,557			286,564
Interest expense		(743,023	)		(4,020	)
Loss on derivative contracts		(2,458,165	)		-

Loss before minority interest		(5,915,699	)		(3,898,985	)

Minority interest		376,270			-

Net loss		(5,539,429	)		(3,898,985	)

Dividend on Series A Convertible Preferred		(510,928	)		-

Net loss attibutable to common stockholders	$	(6,050,357	)	$	(3,898,985	)

Earnings per common share
Basic and diluted	$	(0.28	)	$	(0.20	)

Weighted average number of common shares outstanding
Basic and diluted		21,253,995			19,201,991

The accompanying notes are an integral part of these financial statements.

F-3

PETRO RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

	Common Stock						Additional						Total
	Number						Paid-in			Accumulated			Shareholders'
	of Shares			Total			Capital			Deficit			Equity

Balance, December 31, 2005		16,191,317			161,913			5,038,037			(415,748	)		4,784,202

Shares and warrants sold in private placement, net		3,486,000			34,860			8,180,140			-			8,215,000
Stock options issued to the board of directors								1,598,541						1,598,541
Net loss for the year ended December 31, 2006		-			-			-			(3,898,985	)		(3,898,985	)
Balance, December 31, 2006		19,677,317		$	196,773		$	14,816,718		$	(4,314,733	)	$	10,698,758

Exchange of preferred stock for common stock and warrants		(1,573,800	)		(15,738	)		(4,705,663	)		-			(4,721,401	)
Legal expense on preferred stock		-			-			(14,705	)		-			(14,705	)
Preferred stock dividend		-			-			-			(510,928	)		(510,928	)
Restricted stock issued to Chief Financial Officer		25,000			250			62,750			-			63,000
Shares issued for purchase of property		3,144,655			31,447			10,691,827			-			10,723,274
Stock options issued for consulting services		-			-			58,000			-			58,000
Stock options to board of directors		-			-			913,701			-			913,701
Stock options to Chief Financial Officer		-			-			83,135			-			83,135
Stock issued for cash		15,326,200			153,262			28,353,470			-			28,506,732
Offering costs to issue stock		-			-			(535,718	)		-			(535,718	)
Net loss for the year ended December 31, 2007		-			-			-			(5,539,429	)		(5,539,429	)
Balance, December 31, 2007		36,599,372			365,994			49,723,515			(10,365,090	)		39,724,419

The accompanying notes are an integral part of these financial statements

F-4

PETRO RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended
	December 31
	2007			2006

Cash flows from operating activities
Net loss	$	(5,539,429	)	$	(3,898,985	)
Adjustments to reconcile net income to net cash
(used in) provided by operating activities:
Minority interest		(376,270	)		-
Depletion, depreciation, and accretion		1,781,263			304,396
Amortization included in interest expense		468,938			-
Amortization of insurance expense		125,972			-
Impairment		95,272			614,770
Dry hole costs		1,310,988			2,141,907
Issuance of common stock and stock options for services		1,117,836			1,598,541
Gain on sale of property		-			(1,394,754	)
Unrealized loss on derivative contracts		1,832,316			-
Changes in operating assets and liabilities:
Accounts receivable and accrued revenue		(833,263	)		(91,344	)
Prepaid expenses		-			(11,602	)
Accounts payable		626,873			77,726
Accrued expenses		243,119			(95,464	)
Net cash provided by (used in) operating activities		853,615			(754,809	)

Cash flows from investing activities
Capital expenditures		(14,266,262	)		(8,240,421	)
Acquisition of Williston Basin		(14,097,855	)		-
Deposits		-			(10,257	)
Investment in partnership		(1,599,840	)		(2,293,104	)
Proceeds from sale of properties		-			3,953,785
Net cash used in investing activities		(29,963,957	)		(6,589,997	)

Cash flows from financing activities
Proceeds from sale of common stock, net		27,971,014			8,215,000
Repayment of officer advances		-			(2,500	)
Issuance of preferred stock		2,000,000			-
Costs to issue preferred stock		(14,705	)		-
Financing costs		(3,892,078	)		-
Proceeds from loan		28,534,442			-
Principal payment on loan		(14,373,988	)		-
Net cash provided by financing activities		40,224,685			8,212,500

Net increase (decrease) in cash		11,114,343			867,694
Cash, beginning of period		4,285,204			3,417,510

Cash, end of period	$	15,399,547		$	4,285,204

Supplemental disclosure of cash flow information
Cash paid for interest	$	1,944,388		$	4,020
Cash paid for federal income taxes		-			-

Non-cash transactions
Common stock issued in acquisition of Williston Basin properties		10,723,274			-
Royalty and minority interest issued in connection with debt		4,837,429			-
Preferred stock dividend paid in preferred shares		510,928			-
Cancellation of common stock in exchange for preferred stock		4,721,401			-
Capitalized interest in oil and gas properties		1,675,802			-
Property and equipment included in accounts payable	$	681,731		$	-

The accompanying notes are an integral part of these financial statements

F-5

PETRO RESOURCES CORPORATION

Notes to Financial Statements

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Petro Resources Corporation was incorporated in June 1997 in the State of Delaware under the name Kid Kritter USA, Inc. to engage in the design and manufacture of children’s apparel. Petro terminated that business in 1999. Petro changed its name to Primebuy International, Inc. in February 2002.

Effective May 6, 2003, Petro acquired all the outstanding shares of common stock of Russian Resources Corporation (“RRC”), a private company incorporated in Delaware on February 19, 2002, for 4,189,000 shares of Petro’s common stock, representing 61.4% of Petro’s outstanding shares after the merger. Although Petro acquired RRC, the shareholders of RRC held a majority of the voting interest and RRC management and board of directors assumed operational control of the combined enterprise. Accordingly, this merger was accounted for as a recapitalization, and the historical results of operations presented are those of RRC.

Petro changed its name to Russian Resources Group, Inc. in May 2003. During 2003 and 2004, Petro focused its attention on the analysis and due diligence of certain oil and gas properties in Russia.

In late 2004, Petro terminated all its activities in Russia and redirected its attention to oil and gas exploration and development in the United States. On April 1, 2005, Petro recruited a new management team. In June 2005, Petro changed its name to Petro Resources Corporation.

In February 2007, as more fully discussed in Note 4 below, Petro formed a wholly-owned subsidiary, PRC Williston, LLC, a Delaware limited liability company, for the purpose of acquiring working interests in crude oil and natural gas producing properties

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates.

Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of our financial statements requires us to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses. These estimates are based on information that is currently available to us and on various other assumptions that we believe to be reasonable under the circumstances. Actual results could vary significantly from those estimates under different assumptions and conditions.

Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial condition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.

Successful Efforts Accounting

Petro uses the successful efforts method of accounting for crude oil and natural gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and related asset retirement costs are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves on a field basis. Unproved leasehold costs are capitalized pending the results of exploration efforts. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are charged to expense when incurred.

Principles of Consolidation.

The accompanying consolidated financial statements include Petro Resources Corporation and its wholly−owned subsidiary PRC Williston, LLC. Intercompany accounts and transactions have been eliminated in consolidation.

F-6

Deferred financing costs.

In connection with debt financings in 2007, Petro Resources has paid $3,892,078 in fees. These fees were recorded as deferred financing costs and are being amortized over the life of the loans using the effective interest rate method or straight line method when the debt is in the form of a line of credit.

Convertible instruments.

We follow SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” and SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as well as EITF Issue No. 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features of Contingency Adjustment Conversion Ratios” in determining if there are any bifurcation or beneficial conversion issues.

Derivative Financial Instruments.

We use commodity derivative financial instruments, typically options and swaps, to manage the risk associated with fluctuations in oil and gas prices. We account for derivatives under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, and related interpretations and amendments. SFAS No. 133, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Our oil and gas price swaps are not designated as hedges. In accordance with provisions of SFAS No. 133, these instruments have been marked-to-market through earnings.

Valuation of Property and Equipment

Petro accounts for the impairment and disposition of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 requires that the Company’s long-lived assets, including its oil and gas properties, be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. An impairment charge to current operations is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the differences in the carrying value and estimated fair value of the impaired asset.

SFAS 144 provides for future revenue from the Company’s oil and gas production to be estimated based upon prices at which management reasonably estimates such products will be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s oil and gas properties in subsequent periods.

The long-lived assets of the Company, which are subject to evaluation, consist primarily of oil and gas properties. Due to the regularly scheduled impairment reviews by management, Petro recognized a non-cash, pre-tax charge against earnings of $95,272 and $614,770 in 2007 and 2006, respectively.

Income Taxes

Petro uses the asset liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities, and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carryforwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization.

Cash and cash equivalents

Cash and cash equivalents include cash in banks and highly liquid debt securities that have original maturities of three months or less.

F-7

Revenue Recognition - Revenues associated with sales of crude oil, natural gas, natural gas liquids, petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.

Revenues from the production of natural gas and crude oil properties, in which we have an interest with other producers, are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.

Derivative Instruments - All derivative instruments are recorded on the balance sheet at fair value in either prepaid expenses and other current assets, other assets, other accruals, or other liabilities and deferred credits. Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives that are not accounted for as hedges under Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge will be recorded on the balance sheet in accumulated other comprehensive income until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings.

Oil and Gas Exploration and Development - - Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.

Property Acquisition Costs - Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants and equipment. Leasehold impairment is recognized based on exploratory experience and management's judgment. Upon discovery of commercial reserves, leasehold costs are transferred to proved properties.

Exploratory Costs - Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made.

Management reviews exploratory well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the exploratory well costs as a dry hole when it judges that the potential field does not warrant further investment in the near term.

Development Costs - Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.

Depletion and Amortization - Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves.

F-8

Capitalized Interest - Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.

Impairment of Properties, Plants and Equipment - Properties, plants and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as impairments in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets-generally on a field-by-field basis for exploration and production assets. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. If the future production price risk has been hedged, the hedged price is used in the calculations for the period and quantities hedged. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation. The price and cost outlook assumptions used in impairment reviews differ from the assumptions used in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities. In that disclosure, SFAS No. 69, "Disclosures about Oil and Gas Producing Activities," requires inclusion of only proved reserves and the use of prices and costs at the balance sheet date, with no projection for future changes in assumptions.

Asset Retirement Obligations and Environmental Costs -- We record the fair value of legal obligations to retire and remove long-lived assets in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related properties, plants and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plants and equipment is depreciated over the useful life of the related asset. See Note 6 - Asset Retirement Obligations and Accrued Environmental Costs, for additional information.

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable and estimable.

F-9

Cost Method

Under the guidance of Emerging Issues Task Force D-46, Accounting for Limited Partnership Investments Petro uses the cost method to account for its limited partnership and membership interest that represent an ownership interest that exceeds 5% of the applicable entity, but is less than 50% of the applicable entity. Under the cost method of accounting, Petro’s investment is stated at the original investment amount and increased or decreased by subsequent investments or distributions. During fiscal year 2007 and 2006, as more fully described in Note 5, Petro accounted for its investment in Hall-Houston Exploration II, L.P. under the cost method of accounting.

Share Based Compensation

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payments” (“FAS 123R”). Petro adopted the disclosure requirements of FAS 123R as of January 1, 2006 using the modified prospective transition method approach as allowed under FAS 123R. FAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. FAS 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. FAS 123R requires that the fair value of such equity instruments be recognized as expense in the historical financial statements as services are performed.

Loss per Common Share

Basic and diluted net loss per share calculations are calculated on the basis of the weighted average number of common shares outstanding during the year. For the years ended December 31, 2007 and 2006, there were no potential common equivalent shares used in the calculation of weighted average common shares outstanding as the effect would be anti-dilutive because of the net loss.

Recently Issued Accounting Pronouncements.

In December 2007, the FASB issued Statement SFAS No. 141, Business Combinations (SFAS 141R), and Statement of Financial Accounting Standards No. 160, Accounting and Reporting of Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB No. 51 (SFAS 160). SFAS 141R and SFAS 160 will significantly change the accounting for and reporting of business combination transactions and noncontrolling (minority) interests in consolidated financial statements. SFAS 141R retains the fundamental requirements in Statement 141, Business Combinations, while providing additional definitions, such as the definition of the acquirer in a purchase and improvements in the application of how the acquisition method is applied. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests, and classified as a component of equity. These Statements become simultaneously effective January 1, 2009. Early adoption is not permitted. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results financial position or cash flows.

In May 2007, the FASB issued FSP No. FIN 48-1, Definition of Settlement in FASB Interpretation No. 48, (FIN 48-1) which amends FIN 48 and provides guidance concerning how an entity should determine whether a tax position is “effectively,” rather than the previously required “ultimately,” settled for the purpose of recognizing previously unrecognized tax benefits. In addition, FIN 48-1 provides guidance on determining whether a tax position has been effectively settled. The guidance in FIN 48-1 is effective upon the initial January 1, 2007 adoption of FIN 48. Companies that have not applied this guidance must retroactively apply the provisions of this FSP to the date of the initial adoption of FIN 48. The Company has adopted FIN 48-1 and no retroactive adjustments were necessary.

In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115 (SFAS 159), which permits entities to choose to measure many financial instruments and certain other items at fair value (the Fair Value Option). Election of the Fair Value Option is made on an instrument-by-instrument basis and is irrevocable. At the adoption date, unrealized gains and losses on financial assets and liabilities for which the Fair Value Option has been elected would be reported as a cumulative adjustment to beginning retained earnings. If the Company elects the Fair Value Option for certain financial assets and liabilities, the Company will report unrealized gains and losses due to changes in fair value in earnings at each subsequent reporting date. The provisions of SFAS 159 are effective January 1, 2008. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results, financial position or cash flows.

In September 2006, the FASB issued SFAS 157, Fair Value Measurements (SFAS 157), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This pronouncement applies to other standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. The provisions of SFAS 157 are effective for the Company on January 1, 2008. The Company is currently assessing the impact, if any that the adoption of this pronouncement will have on the Company’s operating results, financial position or cash flows.

Reclassification of Prior-Year Balances

Certain prior-year balances in the consolidated statements of cash flows have been reclassified to correspond with current-year classifications.

F-10

NOTE 3 - FINANCIAL INSTRUMENTS AND DERIVATIVES

In conjunction with Petro’s acquisition of the producing properties in North Dakota, Petro entered into hedging arrangements with Nexen Marketing USA, Inc., which is also the purchaser of the oil from these properties. The hedging arrangements are oil swaps priced against the monthly settlement price as posted by the New York Mercantile Exchange (“NYMEX”) for West Texas Intermediate Crude (“WTI”) beginning March 2007 and continuing for a period of 36 months.

As of December 31, 2007, we had the following commodity swaps in place:

	Barrels per quarter	Barrels per day	Price per barrel
2008
First quarter	15,400	169	$66.74
Second quarter	14,446	159	$73.23
Third quarter	12,843	140	$71.47
Fourth quarter	9,200	100	$65.70

2009
First quarter	8,225	91	$65.62
Second quarter	6,825	75	$65.40
Third quarter	6,900	75	$65.40
Fourth quarter	6,900	75	$65.40

2010
First quarter	4,425	49	$65.40

During the year ended December 31, 2007, we incurred a net loss of $2,458,165 related to derivative contracts. Included in this loss was $625,849 of realized losses related to settled contracts and $1,832,316 of unrealized losses related to unsettled contracts. Unrealized losses are based on the changes in the fair value of derivative instruments covering positions beyond December 31, 2007.

Fair Values of Financial Instruments

We used the following method and assumptions to estimate the fair value of financial instruments:

Ø	Cash and cash equivalents: The carrying amount reported on the balance sheet approximates fair value.

Ø	Accounts and notes receivable: The carrying amount reported on the balance sheet approximates fair value.

Ø	Debt: The carrying amount of our floating-rate debt approximates fair value.

Swaps: Fair value is estimated based on forward market prices and approximates the net gains and losses that would have been realized if the contracts had been closed out a year-end. When forward market prices are not available, they are estimated using the forward prices of a similar commodity with adjustments for differences in quality or location.

Ø	Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the ICE Futures, or other traded exchanges.

Ø	Forward-exchange contracts: Fair value is estimated by comparing the contract rate to the forward rate in effect on December 31 and approximates the net gains and losses that would have been realized if the contracts had been closed out at year-end.

NOTE 4 - WILLISTON BASIN ACQUISITION

On February 16, 2007, we closed on the acquisition of an approximate 43% average working interest in 15 fields located in the Williston Basin in North Dakota. Pursuant to the Purchase and Sale Agreement dated December 11, 2006 between Eagle Operating Inc., of Kenmare, North Dakota, and our newly formed wholly-owned subsidiary, PRC Williston, LLC, a Delaware limited liability company, we acquired 50% of Eagle Operating’s working interest in approximately 15,000 acres and 150 wells which produced approximately 350 barrels of oil per day net to PRC Williston’s interest during December 2007. The acquisition was accounted for using the purchase method under SFAS No. 141. Eagle Operating is the operator of the Williston Basin properties.

As consideration for the working interest, our preliminary purchase price included $12,653,648 in cash, which included $2,653,648 of additional well costs incurred by Eagle Operating, and issued 3,144,655 shares of our common stock valued at $10,723,274 (based on the average of the high and low price per share on the closing date) to Eagle Operating. In addition, we incurred $1,744,207 in fees and expenses related to the acquisition and assumed the asset retirement obligation associated with these properties of $1,250,323. Further, we agreed to contribute development capital towards 100% of the mutually agreed upon joint capital costs of the existing secondary recovery and development program and in other joint participations with Eagle Operating over a five year period not to exceed $45 million.

The acquisition was financed by borrowings under a $75 million credit facility. In connection with obtaining the credit facility, we granted the lender an aggregate 4% overriding royalty interest and we entered into a participation agreement. (see Note 8)

F-11

The preliminary purchase price allocation of the assets acquired on February 16, 2007 is as follows:

Assets
Oil and gas properties	$	26,371,452

Liabilities and equity
Asset retirement obligation	$	(1,250,323	)
	$	25,121,129

The results of this acquisition are included in the consolidated financial statements from the date of acquisition. Unaudited pro forma operating results for Petro Resources, assuming the acquisition occurred at January 1, 2006, are as follows:

	Year ended December 31, 2007			Year ended December 31, 2006

Revenue	$	7,615,876		$	6,308,916

Net loss		(6,353,774	)		(6,951,027	)

Net loss per common share	$	(0.30	)	$	(0.36	)

The unaudited pro forma results are not necessarily indicative of what would have occurred if the acquisition had been in effect for the period presented. In addition, they are not intended to be a projection of future results.

NOTE 5 - INVESTMENT IN LIMITED PARTNERSHIP

In April 2006, Petro Resources agreed to purchase up to $8 million of limited partnership interests in Hall-Houston Exploration II, L.P., a newly formed oil and gas exploration and development partnership that intends to focus primarily offshore in the Gulf of Mexico. In April 2006, Hall-Houston Exploration II, L.P. received commitments for a total of $150 million from the sale of limited partnership interests. Petro Resources’ interest in Hall-Houston Exploration II, L. P. represents approximately 5.3% of all interests held by limited partners. The limited partnership commenced exploration activities in the third quarter of 2006. Pursuant to the limited partnership agreement, the limited partners of Hall-Houston Exploration II, L. P. are required to fund their investment in the partnership based on calls for capital made by the general partner from time to time. The general partner can issue a call for capital contributions at any time, and from time to time, over a three year period expiring in April 2009. As of December 31, 2007, Petro Resources had funded $3,892,944 of its $8 million commitment.

NOTE 6 - ASSET RETIREMENT OBLIGATIONS

SFAS Interpretation 47 (“FIN 47”), “Accounting for Conditional Asset Retirement Obligations”, an interpretation of SFAS No. 143, clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. FIN 47 requires a liability to be recognized for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 was effective for fiscal years ending after December 15, 2005.

	2007			2006
Asset retirement obligation at beginning of period	$	30,653		$	10,337
Purchase		1,250,323
Liabilities incurred		42,407			21,751
Liabilities settled		-			(2,199	)
Accretion expense		111,301			965
Revisions in estimated liabilities		(570	)		(201	)
Asset retirement obligation at end of period	$	1,434,114		$	30,653

F-12

NOTE 7 – ACCUMULATED PRODUCTION FLOOR PAYMENTS

On February 16, 2007, we acquired from Eagle Operating, Inc. an interest in 15 producing oil fields located in the Williston Basin of North Dakota. For a period of thirty-six months following the acquisition date, Eagle Operating has guaranteed that PRC Williston’s share of gross monthly production revenue from the properties will not be less than the financial equivalent of 300 barrels of oil per day multiplied by the number of days in a given month (the product referred to as the “production floor”). In the event that our net share of gross production for any month is less than the production floor, Eagle Operating is obligated to pay to Petro Resources, in cash, an amount equal to the difference between the production floor and the actual net barrels to our interest multiplied by the average price of crude oil paid for the oil production from the properties for that month (the “production floor payment”). During the thirty-six month period, for any month in which our net share of oil production exceeds the production floor, Eagle Operating shall be entitled to recover a portion of the production floor payments previously made to us, also in the form of a cash payment, not to exceed the amount by which our net share of oil production exceeds the production floor for such month (a “production floor reimbursement”). At the end of the thirty-six month period, we are obligated to repay to Eagle Operating, in cash, the amount of cumulative production floor payments, net of any production floor reimbursements. At December 31, 2007, there were no amounts due related to the production floor payments.

NOTE 8 – NOTES PAYABLE

In connection with the Williston Basin acquisition, we entered into a $75 million credit agreement (the “Credit Facility”) pursuant to which the lenders have agreed to initially loan us $20,273,183 for purposes of financing our Williston Basin acquisition, including certain transaction costs and fees, certain costs of drilling and development of oil and gas properties, and general working capital. Any further advances under the Credit Facility are to be used for drilling and development or to fund additional oil and gas property acquisitions, and are subject to certain conditions and the prior approval of the lenders.

All funds borrowed under the Credit Facility bear interest at a rate equal to (x) the greater of the prime rate or 7.5%, plus (y) 2%, with interest payable monthly. The principal amount of advances outstanding under the credit agreement are repayable monthly in an amount approximating 100% of PRC Williston’s cash on hand (from any source) less all permitted costs and expenses paid by PRC Williston for the monthly period.

The following table reflects the estimated maturities of this loan based on our most recent cash projections:

Years ending:

June 30, 2008	$	2,495,947
June 30, 2009		6,304,190
June 30, 2010		5,487,055

Total	$	14,287,192

PRC Williston’s obligations under the credit agreement have been secured by its grant of a first priority security interest and mortgage on all of its assets. Petro Resources has guaranteed the performance of PRC Williston’s obligations under the credit agreement and related agreements and has secured its guarantee by granting to the lenders a first priority security interest in its ownership interest in PRC Williston.

Under the credit agreement, Petro Resources was required to make an equity contribution of at least $5 million to PRC Williston within one hundred eighty days of February 16, 2007, the proceeds of which were to be used to pay down the outstanding principal under the credit agreement. In connection with the acquisition, we entered into equity participation agreements with the lenders pursuant to which we agreed to pay to the lenders an aggregate of 12.5% of all distributions paid to the owners of PRC Williston, which at this time is 100% owned by Petro Resources. PRC Williston also granted the lenders a 4% overriding royalty interest, proportionally reduced by our net revenue interest, in its oil and gas leases. The participation and overriding royalty interest was valued at $4,537,826 and the loan origination fee of $299,604 is included in the notes payable discount. Also in connection with debt financings in 2007, Petro Resources paid $3,892,078 in fees, of which approximately $1.0 million was related to waivers and additional financing of $7.4 million. These fees were recorded as deferred financing costs. Both the discount and the deferred financing costs are being amortized over the life of the loans using the straight line method due to the fact that the credit facility is structured as a line of credit.

The credit agreement obligates PRC Williston to comply with certain financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio beginning with the quarter ending on June 30, 2007, a minimum interest coverage ratio and debt coverage ratios based on earnings and petroleum reserves, as such ratios are defined in the agreement. In addition, the credit agreement also provides for restrictions on additional borrowings, payments to members, investments and capital expenditures. PRC Williston was in violation of certain of these covenants and entered into an agreement with the lender waiving the required calculation of the financial covenants through December 31, 2007. As a result of this default, the entire credit agreement amount was classified to current liabilities as of December 31, 2007.

F-13

On March 1, 2007, Petro Resources signed a promissory note with a finance company to finance its various insurance policies. The interest rate on the note is 7.90% with payments of $13,225 per month beginning April 1, 2007 and the final payment due February 1, 2008. The note is secured by the insurance policies. At December 31, 2007, the outstanding balance on the note was $13,150.

The following is a summary of our debt:

	2007
PRC Williston Credit Facility	$	14,287,192
Discount on Credit Facility, net of amortization		(2,956,206	)
Other Note payable		13,150
Total debt	$	11,344,136

NOTE 9 - MINORITY INTEREST

In connection with the Williston Basin acquisition, we entered into equity participation agreements with the lenders pursuant to which we agreed to pay to the lenders an aggregate of 12.5% of all distributions paid to the owners of PRC Williston, which at this time is 100% owned by Petro Resources. The equity participation agreements were valued at $3,401,655 and accounted for as a minority interest in PRC Williston.

	Minority Interest
Value of minority interest at acquisition	$	3,401,645
Earnings (loss) to minority interest		(376,270	)
Minority interest at December 31, 2007	$	3,025,375

NOTE 10—SERIES A PREFERRED STOCK

On April 3, 2007, we completed the sale of 2,240,467 shares of our Series A Convertible Preferred Stock (“Series A Preferred Stock”) to two funds managed by Touradji Capital Management, LP in consideration for (i) payment of $2 million; (ii) return of 1,573,800 shares of its common stock; and (iii) the return of 160,000 common stock purchase warrants with a deemed aggregate value of $4,721,400, or $3.00 per common share. The total aggregate value of the Series A Preferred Stock recorded was $6,721,401 which represents the fair market value of the instrument. The Series A Preferred Stock was recorded as a temporary equity in accordance with SFAS No. 150 for mandatorily redeemable preferred stock with contingency features. During 2007, we issued 170,309 share of our Series A Preferred Stock, valued at $3 per share as agreed upon in the Preferred Stock Purchase Agreement, in lieu of cash payments in satisfaction of the Preferred Stock dividend requirement.

NOTE 11 - SHARE BASED COMPENSATION

In March 2006, Petro Resources adopted the 2006 Stock Incentive Plan. Under the Plan, options may be granted to key employees and other persons who contribute to the success of Petro. Petro Resources originally reserved 1,500,000 shares of common stock for the Plan. In June 2007, Petro increased the authorized shares to 3,000,000. No options were exercised during the years ended December 31, 2007 and 2006.

F-14

Petro accounts for stock based compensation arrangements in accordance with the provisions of SFAS No. 123R, “Share-Based Payment,” which revised SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123R supersedes APB Opinion 25, “Accounting for Stock Issued to Employees” and amends SFAS No. 95, “Statement of Cash Flows.” SFAS No. 123R requires measurement and recording to the financial statements of the costs of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, recognized over the period during which an employee is required to provide services in exchange for such award. Petro has implemented SFAS 123R effective January 1, 2006.

During the year ended December 31, 2006, Petro added five new members to its Board of Directors and granted each of them 200,000 options to purchase Petro’s common stock at $3.80 per share. These options vest one fourth immediately and one fourth on each of the next three March 1 anniversaries. The options were valued using the Black-Scholes model with the following assumptions: stock price between $3.80 and $5.50 (the selling price of the stock on the grant date); $3.80 exercise price; 108% volatility; five-year term; zero dividend; and discount rate between 4.63% and 4.99%.

On March 15, 2007, we granted a consultant options to purchase 25,000 shares of Petro Resources’s common stock at $3.80 per share. We recorded $58,000 of expense, equal to the fair value of the options granted, in connection with this issuance. The options were valued using the Black-Scholes model with the following assumptions: $2.99 quoted stock price; $3.80 exercise price; 110.05% volatility; 2.5 year estimated life; zero dividend; and 4.54% discount rate.

On June 1, 2007, we granted 100,000 stock options to our new Chief Financial Officer. The options have an exercise price of $2.50 per share. 25,000 options vested immediately and the remaining 75,000 options will be issued and will vest annually on June 1, 2008, 2009 and 2010. The stock options have a 5 year term expiring on June 1, 2012. The options were valued using the Black-Scholes model with following assumption: $2.50 quoted stock price; $2.50 exercise price; 119.41% volatility; 3.25 year estimated life; zero dividend; 5.0% discount rate.

Petro Resources recognized stock compensation expense of $1,117,836 and $1,598,541 for 2007 and 2006 respectively.

A summary of option activity for the years ended December 31, 2006 and 2007 is presented below:

	Shares	Weighted-Average Exercise Price
Outstanding at January 1, 2006	-	$	-
Granted	1,000,000		3.80
Exercised, forfeited, or expired	-		-
Outstanding at December 31, 2006	1,000,000	$	3.80
Granted	125,000		2.76
Exercised, forfeited, or expired	-		-
Outstanding at December 31, 2007	1,125,000	$	3.68

Exercisable at December 31, 2006	250,000	$	3.80
Exercisable at December 31, 2007	550,000	$	3.74

F-15

A summary of Petro Resources non-vested shares as of December 31, 2007 and 2006 is presented below:

Non-vested Shares		Shares
Non-vested at January 1, 2006		-
Granted		1,000,000
Vested		(250,000)
Forfeited		-
Non-vested at December 31, 2006		750,000
Granted		100,000
Vested		(275,000)
Forfeited		-

Non-vested at December 31, 2007		575,000

Total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Plan was $1,334,530 and $2,056,264 as of December 31, 2007 and 2006 respectively. That cost at December 31, 2007 is expected to be recognized over a weighted-average period of 2.1 years. The aggregate intrinsic value for options was $0; and the weighted average remaining contract life was 3.30 years. A summary of warrant activity for the years ended December 31, 2006 and 2007 is presented below:

	Warrants			Weighted Average Exercise Price
Outstanding at January 1, 2006		5,800,650		$	2.00
Issued		1,198,312			3.00
Outstanding at December 31, 2006		6,998,962			2.17
Return of warrants in exchange for preferred stock		(160,000	)		3.00
Outstanding at December 31, 2007		6,838,962		$	2.15

The aggregate intrinisic value for warrants was $0; and the weighted average remaining contract life was 2.91 years.

NOTE 12 - SHAREHOLDERS’ EQUITY

On November 2, 2007, we closed our public offering of 14,000,000 shares of common stock generating approximately $25.5 million in net proceeds. Additionally, the underwriters purchased an additional 1,326,200 shares of common stock for approximately $2.5 million.

On February 16, 2007, we issued 3,144,655 shares of common stock to Eagle Operating in connection with the purchase of the Williston Basin properties. The shares were valued at $10,723,274 based on the average of the high and low price per share on the closing date.

In June 2007 we also issued 25,000 shares of restricted common stock, which vested immediately, to our new Chief Financial Officer. In connection with this issuance, we recorded $63,000 as compensation expense based on the closing price of our common stock on June 1, 2007. We also agreed to issue 25,000 additional restricted common shares on June 1, 2008, 2009 and 2010, which vest immediately upon each respective issuance, for an aggregate of 75,000 shares. Compensation expense related to these shares is accrued monthly based on the average monthly quoted shares price.

In connection with the issuance of preferred stock, we received and cancelled 1,573,800 shares of common stock and recorded a reduction in common stock and additional paid in capital totaling $4,721,401. (See Note 10) In addition, we recorded a reduction of $14,705 in additional paid in capital associated with the costs of issuing the preferred shares.

In June 2007, Petro Resources increased its authorized common stock (.01 par value) from 50 million to 100 million shares.

In January 2006, we adopted SFAS No. 123(R), Share-Based Payment (SFAS 123(R)). SFAS 123(R) revises SFAS No. 123, Accounting for Stock-Based Compensation, and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. The Company used the modified prospective application method as detailed in SFAS 123(R).

As allowed by SFAS 123(R), the Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options and stock settled stock appreciation rights.

F-16

The assumptions used in the fair value method calculation for the years ended December 31, 2007 and 2006 are disclosed in the following table:


	2007 (1)		2006
Weighted average value per option granted during the period (2)	$	1.77	$	3.80
Assumptions (3):
Stock price volatility		110-119%		108%
Risk free rate of return		4.54 to 5.0%		4.63-4.99%

Expected term		2.5 to 5.0 years		5.0 years

(1)	Our estimated future forfeiture rate is zero.
(2)	Calculated using the Black-Scholes fair value based method.
(3)	We do not pay dividends on our common stock.

NOTE 13 - INCOME TAXES

Reconciliation between the actual tax expense (benefit) and income taxes computed by applying the U.S. federal income tax rate to income from continuing operations before income taxes is as follows:

	2007		2006
Computed at U.S. statutory rate at 34% in 2007 and 15% in 2006	$	1,883,407	$	(584,848	)
Permanent differences		383,620		239,781
Changes in valuation allowance		1,499,787		345,067
Total	$	0	$	0

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred liabilities are presented below.

	2007			2006

Deferred tax assets:
Net operating loss carryforwards	$	2,513,904		$	345,067
Derivatives		622,987
Less valuation allowance		(1,094,375	)		(345,067	)
		2,042,516			0

Deferred tax liabilities:
Oil and gas properties:		(2,042,516	)		0
	$	0		$	0

At December 31, 2007, Petro had net operating loss carryforwards for federal income tax purposes of approximately $15,037,712 that may be offset against future taxable income. Petro has established a valuation allowance for the full amount of the deferred tax assets as management does not currently believe that it is more likely than not that these assets will be recovered in the foreseeable future. To the extent not utilized, the net operating loss carryforwards will expire in 2027.

F-17

NOTE 14 - SUBSEQUENT EVENTS

On March 1, 2008 we granted 100,000 stock options to our new Chief Operating Officer. The options have an exercise price of $1.70 per share. Twenty five thousand options vested on March 1, 2008 and the remaining 75,000 options will be issued and will vest annually on March 1, 2009, 2010 and 2011. The stock options have a 5 year term expiring on March 1, 2013. The options were valued using the Black-Sholes model with following assumption: $1.70 quoted stock price; $1.70 exercise price; 104% volatility; 3.25 year estimated life; zero dividend; 1.87% discount rate. The fair value of these options was $112,381.

On March 1, 2008 we also granted 130,000 shares of restricted common stock to our new Chief Operating Officer. These common shares vest at 40,000 immediately and 30,000 each on June 1, 2009, 2010 and 2011. The fair value of these restricted common shares is $218,400 and will be recognized over the applicable service term.

NOTE 15 - SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

The following table sets forth the capitalized costs and associated accumulated depreciation, depletion and amortization, including impairments, related to Petro’s oil and gas production, exploration and development activities:

	2007			2006
Unproved oil and gas properties	$	24,676,434		$	3,728,112
Proved oil and gas properties		21,606,881			1,446,326
		46,283,315			5,174,438
Accumulated depletion, depreciation and impairment		(2,670,453	)		(918,368	)
	$	43,612,862		$	4,256,070

The following table sets forth the costs incurred in oil and gas property acquisition, exploration, and development activities.

	2007		2006
Purchase of non-producing leases	$	16,791,029	$	5,746,260
Purchase of producing properties		4,551,382		0
Exploration costs		3,081,058		2,438,180
Development costs		16,704,232		183,126
Asset retirement obligation		1,403,461		21,751
	$	42,531,162	$	8,389,317

Oil and Gas Reserve Information

Proved oil and gas reserve quantities are based on estimates prepared by Cawley, Gillespie & Associates, Inc. and DeGolyer & MacNaughton, Petro’s engineers. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact.

F-18

Total Proved Reserves

	Crude oil and Condensate (Thousand of Barrels)			Natural Gas (Millions of Cubic Feet)
Balance December 31, 2005		0		0
Extensions, discoveries and other additions		8.4		136.4
Production		(0.5	)	(20.3	)
Balance December 31, 2006		7.9		116.1
Extensions, discoveries and other additions		362.9		1,265.0
Revisions of previous estimates		19.8		(211.8)
Purchase of reserves in place		1,370.0		1,064.3
Improved recovery		708.5		0
Production		(99.4	)	(151.6)
Balance December 31, 2007		2,369.7		2,082.0

Developed reserves, included above
December 31, 2006	7.9	41.0
December 31, 2007	1,411.8	1,069.9

Future Net Cash Flows

Future cash inflows are based on year-end oil and gas prices except in those instances where future natural gas or oil sales are covered by physical contract terms providing for higher or lower amounts. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

The following table sets forth unaudited information concerning future net cash flows for oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of Petro’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.

	2007			2006
Cash inflows	$	208,181,173		$	1,047,053
Production costs		(76,758,323	)		(342,659	)
Development costs		(12,312,808	)		0
Income tax expense		(35,384,592	)		0
10 percent discount rate		(43,613,756	)		(124,558	)
Discounted future net cash flows	$	40,111,694		$	579,836

Changes in Standardized Measure of Discounted Future Cash Flows

	2007			2006
Beginning balance		579,836			-
Purchases		24,039,320			-
Extensions, discoveries and improved recoveries		26,551,353			676,080
Sales of oil and gas produced		(3,410,012	)		(96,244	)
Development cost incurred during the year		3,129,601			-
Changes in estimated development costs		(9,066,693	)		-
Net changes in prices and production costs		10,293,567			-
Revisions of previous quantity estimates		(26,218	)		-
Accretion of discount		2,230,129			-
Net change in income taxes		(14,209,189	)		-
Ending balance		40,111,694			579,836

F-19

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

No applicable.

Item 9A(T).

CONTROLS AND PROCEDURES

Our chief executive officer and chief financial officer have reviewed and continue to evaluate the effectiveness of our controls and procedures over financial reporting and disclosure (as defined in the Securities Exchange Act of 1934 (“Exchange Act”) Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this annual report. The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. This term refers to the controls and procedures of our company that are designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating our controls and procedures over financial reporting and disclosure, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Evaluation of Disclosure Controls and Procedures. Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2007, our disclosure controls and procedures are effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting that occurred during the fourth quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Our management 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 this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2007. This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

Except as set forth below, the information required by Items 10 through 14 is set forth under the captions “Election of Directors,” “Management,” “Executive Compensation,” “Principal Stockholders” and “Certain Transactions” in Petro Resources Corporation’s definitive Proxy Statement for its 2007 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934, as amended, which sections are incorporated herein by reference as if set forth in full.

Item 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Except as set forth below, the information required by this Item is incorporated by reference to our definitive proxy statement.

Code of Ethics

We have adopted a Code of Conduct that applies to our directors and employees (including our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions), and have posted the text of the policy on our website (www.petroresourcescorp.com). If we make any substantive amendments to our Code of Conduct or grant any waiver, including any implicit waiver, from a provision of the code to our Chief Executive Officer, President, Chief Financial Officer or Chief Accounting Officer and Corporate Controller, we will disclose the nature of such amendment or waiver on that website or in a report on Form 8-K.

Item 11.

EXECUTIVE COMPENSATION

Except as provided below, the information required by this Item is incorporated by reference to our definitive proxy statement.

Information relating to securities authorized for issuance under our equity compensation plans is set forth in “Item 5, Market for Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities” above in this Annual Report.

[39]

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this Item is incorporated by reference to our definitive proxy statement.

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item is incorporated by reference to our definitive proxy statement.

Item 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item is incorporated by reference to our definitive proxy statement.

Item 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial statements

Reference is made to the Index and Financial Statements under Item 8 in Part II hereof where these documents are listed.

(b) Financial statement schedules

Financial statement schedules are either not required or the required information is included in the consolidated financial statements or notes thereto filed under Item 8 in Part II hereof.

The following exhibits are either filed herewith or incorporated herein by reference:

Exhibit Number	Description

3.1 (1)	Certificate of Incorporation of the Registrant, as amended

3.1.1 (6)	Certificate of Amendment to Certificate of Incorporation of the Registrant dated May 10, 2007

3.2 (1)	Amended and Restated Bylaws of the Registrant dated April 14, 2006

3.2.1 (2)	Amendment to Bylaws of the Registrant

3.2.2 (7)	Amendment to Bylaws of the Registrant dated October 12, 2006

4.1 (3)	Certificate of Designations of Preferences and Rights of Series A Preferred Stock

10.1 (1)	Form of Registration Rights Agreement dated August 1, 2005

10.2 (1)	Form of Warrant sold as part of August 2005 private placement

10.3 (1)	Lease Purchase Agreement dated January 10, 2006 between Registrant and The Meridian Resource & Exploration, LLC

10.4 (1)	2006 Stock Incentive Plan*

10.5 (1)	Form of Registration Rights Agreement dated February 17, 2006

10.6 (1)	Form of Warrant sold as part of February 2006 private placement

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10.7 (2)	Subscription Agreement for Hall-Houston Exploration II, L.P.

10.8 (2)	Amended and Restated Agreement of Limited Partnership dated as of April 21, 2006 for Hall-Houston Exploration II, L.P.

10.9 (4)	Purchase and Sale Agreement dated December 11, 2006 with Eagle Operating, Inc.

10.10 (4)	Credit Agreement dated February 16, 2007 between PRC Williston LLC and D.B. Zwirn Special Opportunities Fund, L.P., as administrative agent

10.11 (4)	Security Agreement dated February 16, 2007 Between PRC Williston, LLC and D.B. Zwirn Special Opportunities Fund, L.P., as administrative agent

10.12 (4)	Guaranty and Pledge Agreement dated February 16, 2007 between Registrant and D.B. Zwirn Special Opportunities Fund, L.P., as administrative agent

10.13 (4)	Lease dated September 30, 2006 with Gateway Ridgecrest Inc.

10.14 (3)	Securities Purchase Agreement dated April 3, 2007

10.15 (3)	Registration Rights Agreement dated April 3, 2007

10.16 (5)	Letter Agreement dated May 25, 2007 between Registrant and Harry Lee Stout*

10.17 (6)	Letter Agreement dated August 14, 2007 between PRC Williston LLC and D.B. Zwirn Special Opportunities Fund, L.P., as administrative agent

10.18 (7)	Letter Agreement dated September 19, 2007 between PRC Williston LLC and D.B. Zwirn Special Opportunities Fund, L.P., as administrative agent

21.1 (4)	List of Subsidiaries

23.1	Consent of Malone & Bailey, PC

23.2	Consent of Cawley Gillespie & Associates, Inc

23.3	Consent of DeGolyer & MacNaughton

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 the Chief Executive Officer and Chief Financial Officer provided pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* The referenced exhibit is a management contract, compensatory plan or arrangement.

(1)	Incorporated by reference from Petro Resource Corporation’s Registration Statement on Form SB-2 filed on March 21, 2006.

(2)	Incorporated by reference from Petro Resource Corporation’s Amendment No. 1 to Registration Statement on Form SB-2 filed on June 9, 2006.

(3)	Incorporated by reference from Petro Resources Corporation’s current report on Form 8-K filed on April 4, 2007.

(4)	Incorporated by reference from Petro Resources Corporation’s annual report on Form 10-KSB for the year ended December 31, 2006, filed on April 2, 2007.

(5)	Incorporated by reference from Petro Resources Corporation’s current report on Form 8-K filed on June 1, 2007.

(6)	Incorporated by reference from the Petro Resources Corporation’s quarterly report on Form 10-QSB filed on August 14, 2007.

(7)	Incorporated by reference from the Petro Resources Corporation’s Amendment No. 1 to Registration Statement on Form SB-2 filed on September 21, 2007

[41]

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PETRO RESOURCES CORPORATION

Date: March 31, 2008	By:	/s/ Wayne P. Hall
		Wayne P. Hall
		Chairman of the Board and Chief Executive Officer
		(Authorized Signatory)

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and the capacities and on the dates indicated.

Signature	Title	Date

/s/ Wayne P. Hall	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)	March 31, 2008
Wayne P. Hall



/s/ Harry Lee Stout	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 31, 2008
Harry Lee Stout


/s/ Allen R. McGee	Chief Accounting Officer and Director (Principal Accounting Officer)	March 31, 2008
Allen R. McGee



/s/ Donald L. Kirkendall	Director	March 31, 2008
Donald L. Kirkendall


/s/ J. Raleigh Bailes, Sr.	Director	March 31, 2008
J. Raleigh Bailes, Sr.


/s/ Brad Bynum	Director	March 31, 2008
Brad Bynum


/s/ Gary L. Hall	Director	March 31, 2008
Gary L. Hall


/s/ Joe L. McClaugherty	Director	March 31, 2008
Joe L. McClaugherty


/s/ Steven A. Pfeifer	Director	March 31, 2008
Steven A. Pfeifer

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Magnum Hunter Resources Inactive 10-K2007 FY Annual report

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