- Annual Report (10-K)

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, 2008 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: 001-32997

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	NYSE Amex

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 No x

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 No x

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 No o

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. x

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 o	Accelerated filer o
	Non-accelerated filer o	Smaller reporting company x

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

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: $27,075,429.

As of March 31, 2009, 36,788,172 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 2009 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, 2008

PETRO RESOURCES CORPORATION

Item			Page

PART I

	1.	Business	3
	1A.	Risk Factors	17
	1B.	Unresolved Staff Comments	26
	2.	Properties	26
	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	30
	7A.	Quantitative and Qualitative Disclosures About Market Risk	35
	8.	Financial Statements and Supplementary Data	36
	9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	37
	9A(T).	Controls and Procedures	37
	9B.	Other Information	37

PART III

	10.	Directors, Executive Officers and Corporate Governance	38
	11.	Executive Compensation	38
	12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	38
	13.	Certain Relationships and Related Transactions, and Director Independence	38
	14.	Principal Accountant Fees and Services	38
	15.	Exhibits and Financial Statement Schedules	38

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 2009 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 is an independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the United States. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team along with that of our operating partners.

We have been successful in creating and expanding a balanced portfolio consisting of producing properties and prospects that are geologically and geographically diverse, including producing properties, secondary enhanced oil recovery projects, and exploration prospects. This diversity provides projects with varied payout periods, helping us to remain competitive in volatile markets. We target low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Texas, Louisiana, North Dakota, New Mexico and Kentucky. We currently own interests in approximately 286,282 gross (50,611 net) leasehold acres, of which 261,147 gross (43,281 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. In the third quarter of 2007, we increased our oil and gas producing assets with the addition of acreage in the Permian Basin located in West Texas. Subsequently, in 2008, we participated in new prospects located in southwest Louisiana as well as east Texas. As of March 30, 2009, we held interests in approximately 238 producing wells in Texas, Louisiana and North Dakota. Our current drilling inventory includes prospects located in Texas, Louisiana, New Mexico, North Dakota and Kentucky.

We recognize the value of hedging oil and gas production through both derivative and physical contracts to help stabilize cash flow. During the second and third quarters of 2008, we entered into three separate hedging agreements. In June 2008, we purchased put options for crude oil at a price of $110 per bbl for 100 bbls per day of production during 2009. The cost of these crude oil put options was $363,175. We also entered into swap agreements in September covering 207,400 barrels of crude oil at a price of $105 per bbl for the period of October 2008 to December 2011. We incurred no cost in entering these swap agreements. In addition to crude oil hedges, we also hedged natural gas production in October 2008, whereby we purchased natural gas put options at a strike price of $7.75 per mcf for 658 mcf per day (240,000 total mcf) of production during 2009. The cost of these natural gas put options was $200,400.

As of December 31, 2008, our total proved reserves were 3,118 mboe net of production, a gain of 401 mboe from year end 2007 of 2,716 mboe net of production. This gain in proved reserves was the result of gains of 932 mboe from prospect areas in Texas and Louisiana offset by a reduction in North Dakota proved reserves of 531 mboe. The decrease of reserves in North Dakota was precipitated by a lower year end price causing a decrease to the estimated life of the reserves. The total 2008 year end proved reserves is comprised of 2,409 mbbls of crude oil and NGLs and 709 mboe of natural gas.

Our executive offices are located at 777 Post Oak Blvd., Suite 910, Houston, Texas 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, DC 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 year 2008 through the date of this report, we have engaged in the following transactions:

CIT Credit Facility

On September 9, 2008 and amended effective as of March 25, 2009, we entered into a $50 million Credit Agreement (the "Credit Agreement") with certain lenders named in the agreement and CIT Capital USA Inc., as administrative agent for the lenders, and a $15 million Second Lien Term Loan Agreement (the "Second Lien Term Loan Agreement") with certain lenders named in the agreement and CIT Capital USA Inc., as administrative agent for the lenders. All term loans available under the Second Lien Term Loan facility were advanced to us on September 9, 2008 and were used to retire our previously existing credit facility arranged by Petrobridge Investment Management, LLC.

The Credit Agreement provides for a $50 million first lien revolving credit facility, with an initial borrowing base availability of $17 million. The first lien facility may be used for loans and, subject to a $500,000 sublimit, letters of credit. Borrowings under the Credit Agreement may be used to provide working capital for exploration and production purposes, to refinance existing debt, and for general corporate purposes. The maturity date of the Credit Agreement is September 9, 2011.

Borrowings under the Credit Agreement bear interest, at our option, at either a fluctuating base rate or a rate equal to LIBOR plus, in each case, a margin determined based on our utilization of the borrowing base. The Credit Agreement also requires us to satisfy certain financial covenants, including maintaining (A) a ratio of EBITDAX to Interest Expense (as each term is defined in the Credit Agreement) of not less than 2.5:1.0; (B) a ratio of Net Debt (as such term is defined in the Credit Agreement) to EBITDAX of not more than (y) 4.5:1.0 for the fiscal quarters ending December 31, 2008, March 31, 2009, June 30, 2009 and September 30, 2009, and (z) 3.5:1.0 for each fiscal quarter ending thereafter; and (C) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0:1.0. We are also required to enter into certain swap agreements pursuant to the terms of the Credit Agreement.

The Second Lien Term Loan Agreement provides for a $15 million second lien term loan facility. As noted above, all term loans available under the second lien term loan facility were advanced to us on September 9, 2008 and were also used to retire our previously existing credit facility arranged by Petrobridge Investment Management, LLC. The maturity date of the Second Lien Term Loan Agreement is September 9, 2012. Under certain circumstances, we are permitted to repay the term loans prior to the maturity date; however, any payments made on or prior to September 9, 2009 are subject to a prepayment penalty equal to 2% of the amount prepaid, and any payments made after September 9, 2009 but on or before September 9, 2010 are subject to a prepayment penalty equal to 1% of the amount prepaid.

Borrowings under the Second Lien Term Loan Agreement bear interest, at our option, at either a fluctuating base rate plus 6.50% per annum or a rate equal to LIBOR plus 7.50% per annum. The Second Lien Term Loan Agreement also requires us to satisfy certain financial covenants, including maintaining (1) a ratio of Total Reserve Value to Debt (as each term is defined in the Second Lien Term Loan Agreement) of not less than 1.75:1.0; and (2) a ratio of Net Debt to EBITDAX (as each term is defined in the Second Lien Term Loan Agreement) of not more than (a) 4.5:1.0 for the fiscal quarters ending December 31, 2008, March 31, 2009, June 30, 2009 and September 30, 2009, and (b) 4.0:1.0 for each fiscal quarter ending thereafter.

If an event of default occurs and is continuing under either the Credit Agreement or the Second Lien Term Loan Agreement, the lenders may increase the interest rate then in effect by an additional 2% per annum. The Credit Agreement and the Second Lien Term Loan Agreement contain covenants that, among others things, restrict our ability to, with certain exceptions: (i) incur indebtedness; (ii) grant liens; (iii) acquire other companies or assets; (iv) dispose of all or substantially all of our assets or enter into mergers, consolidations or similar transactions; (v) make restricted payments; (vi) enter into transactions with affiliates; and (vii) make capital expenditures.

PRC Williston LLC, our wholly-owned subsidiary, has guaranteed the performance of all of our obligations under the Credit Agreement, the Second Lien Term Loan Agreement and related agreements pursuant to a Guaranty and Collateral Agreement and a Second Lien Guaranty and Collateral Agreement each dated as of September 9, 2008. Subject to certain permitted liens, our obligations have been secured by the grant of a first priority lien on no less than 80% of the value of our and PRC Williston's existing and to-be-acquired oil and gas properties and the grant of a first priority security interest in related personal property of ours and PRC Williston. We also granted a first priority security interest in our ownership interest in PRC Williston, subject only to certain permitted liens.

The Credit Agreement was amended effective as of March 25, 2009 because we were unable to comply with the interest and debt coverage covenants under the terms of the original Credit Agreement and Second Lien Term Loan Agreement for the fiscal quarter ended December 31, 2008. Pursuant to the amendments, the administrative agent and the lenders have agreed to waive these defaults. In connection with the semi-annual review of our borrowing base, lower commodity prices have resulted in our borrowing base for the Credit Agreement being reduced from $17M to $12M. The terms of the Credit Agreement and Second Lien Term Loan Agreement as amended are as follows.

Under the amended Credit Agreement, we must have (A) a ratio of EBITDAX to Interest Expense (as each term is defined in the Credit Agreement) of not less than 2.0:1.0 for the first and second fiscal quarters of 2009, 2.25:1.0 for the third and fourth fiscal quarters of 2009, and 2.5:1.0 for each fiscal quarter thereafter; (B) a ratio of Net Debt (as such term is defined in the Credit Agreement) to EBITDAX of not more than 6.5:1.0 for the fiscal quarters of 2009, 6.0:1.0 for the fiscal quarters of 2010, and 5.0:1 for each fiscal quarter thereafter; and (C) a ratio of First Lien debt to EBITDAX of not more than 2.75:1.0 for each fiscal quarter. Borrowings under the Credit Agreement bear interest, at our option, at either a fluctuating base rate or a rate equal to LIBOR (with a LIBOR floor of 2.50%) plus, in each case, a margin determined based on our utilization of the borrowing base. The amendment includes an increase in the margin of 50 basis points.

Under the amended Second Lien Term Loan Agreement, we must have a ratio of Net Debt to EBITDAX (as each term is defined in the Second Lien Term Loan Agreement) of not more than 6.5:1.0 for the fiscal quarters of 2009 and 2010 and 5.5:1 for the fiscal quarters of 2011 each fiscal quarter ending thereafter. Borrowings under the Second Lien Term Loan Agreement bear interest, at our option, at either a fluctuating base rate plus 6.50% per annum or a rate equal to LIBOR (with a LIBOR floor of 2.50%) plus 7.50% per annum.

As of March 30, 2009, we have drawn $21.5 million, of which $15.0 million was drawn on the Second Lien Term Loan Agreement and $6.5 million was drawn on the Credit Agreement. We are permitted to use the remaining available funds under the Credit Agreement to finance our capital program and fund general corporate purposes.

Series A Preferred Stock Redemption

On September 26, 2008, we redeemed 2,563,712 shares of our outstanding Series A Preferred Stock at an aggregate redemption price of $7,946,735. The shares were held by investment funds managed by Touradji Capital Management. Pursuant to the terms of the Series A Preferred Stock, we were required to redeem all Series A Preferred Stock no later than October 2, 2008. After giving effect to the redemption, there are no shares of Series A Preferred Stock outstanding.

Sale of Hall-Houston Exploration II, L.P. Partnership Interest

On September 26, 2008, we sold our 5.33% limited partner interest in Hall-Houston Exploration II, L. P. pursuant to a Partnership Interest Purchase Agreement dated September 26, 2008, as amended on September 29, 2008. The interest was purchased by a non-affiliated partnership for a cash consideration of $8.0 million and the purchaser’s assumption of the first $1,353,000 of capital calls on the limited partnership interest sold subsequent to September 26, 2008. We have agreed to reimburse the purchaser for up to $754,255 of capital calls on the limited partnership interest sold in excess of the first $1,353,000 of capital calls subsequent to September 26, 2008. We realized a net gain on the sale of the asset of $1.20 million for the quarter ending September 30, 2008, subject to future upward adjustment to the extent that some or all of the $754,255 is not called. The proceeds of the sale of the limited partnership were used to redeem our outstanding shares of Series A Preferred Stock.

Our Oil and Gas Operations

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

· Exploration and production as an operator. In the future, we intend to gain both economic and operational advantages by assuming the role of operator in certain prospects and projects to be located primarily in Texas and Louisiana.

· Negotiated acquisitions of properties. We 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.

· Leasing of prospective acreage. In the course of our business, we identify drilling opportunities on properties that have not yet been leased. At times, we 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 maximize our returns on capital by minimizing our expenditures on general and administrative expenses. We also 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 outsource some of our geological, geophysical, reservoir engineering and land functions in order to help reduce capital requirements.

We 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. From time to time, we 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 in North America. 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 eight 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 employ the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We also pursue alliances with third parties in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. For those properties that we do not operate, we 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 are able to better control total costs and retain flexibility in terms of project management.

Principal Oil and Gas Interests

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 38,000 gross acres. As of the date of this report, 72 of 80 wells have been successfully drilled, completed and turned to sales or are awaiting connection. We intend to drill up to 18 additional wells in this prospect area during 2009. Gross production from the wells at year end 2008 was approximately 18,000 mcf per day and 1300 barrels of oil per day, of which we had a 7.3% net revenue interest. We have budgeted $3.1 million for drilling and workover operations in 2009 for this project.

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, of Kenmare, North Dakota, and our 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 158 wells. For the year ending December 31, 2008, the fields averaged a producing at a rate of approximately 351 barrels of oil equivalent 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. Commencing in November of 2002, Eagle has undertaken re-pressurization in the properties and subsequent conventional and horizontal drilling operations to increase production rates.

Secondary recovery efforts are under way in seven of the 15 producing fields. All fields in which re-pressurization has begun are responding to this secondary recovery effort.

Due to current market conditions and the low prices received for production in the Williston Basin, we do not foresee substantial activity with respect to expanding secondary recovery efforts until such time as is economically feasible.

Surprise Prospect. Surprise is an exploratory prospect area in Nacogdoches County, Texas with natural gas potential from multiple horizons including James Lime, Pettit, Travis Peak, Expanded Bossier, Cotton Valley, and Haynesville Shale. The prospect is operated by Goodrich Petroleum Corporation. The prospect area consists of approximately 3,000 gross (300 net) acres. We have a 10% working interest in the prospect and a net revenue interest of 7.4%. As of the date of this report, four wells have been successfully drilled, completed and turned to sales. A fifth well is currently being drilled. We have the right to acquire a 10% interest in an additional 3,000 gross (300 net) acres through future development for $1,000 per acre, bringing the total potential acreage to approximately 6,000 gross (600 net) acres.

East Chalkley Prospect. Located in Cameron Parish, Louisiana, this developmental project is an exploitation of bypassed oil reserves remaining in a natural gas field. We own a 34% working interest and a 23.5% net revenue interest in this project operated by Centurion Exploration Company. The unit consists of approximately 714 gross acres. During 2008, we drilled one successful well which found pay offsetting, and updip to, Centurion’s #1 Bruiere well. This well is currently producing approximately 120 barrels of oil per day. In 2009, we anticipate drilling a salt water disposal well and one additional well. We expect these operations to cost us approximately $900,000 in 2009.

Leblanc Prospect. The Leblanc Prospect is located in Allen Parish, Louisiana consisting of 240 gross acres and is prospective for oil. We currently own a 50% working interest and anticipate drilling this prospect as operator. The prospect is supported by 3D seismic and substantial subsurface control as well as nearby production. We anticipate drilling operations to commence during 2009 with the associated cost of $500,000.

Chama 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 Rio Arriba County, 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 drilling operations in this prospect have been delayed indefinitely as a result of new and pending regulatory changes at the county and possibly state levels. We anticipate that drilling operations will commence once these regulatory changes have been fully defined and implemented. We do not expect any drilling activities in this prospect area during 2009.

Illinois Basin, Boomerang Prospect . This 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 is 6.8% and the prospect is operated by Approach Resources Incorporated. During 2007, three pilot wells were drilled for initial testing purposes; however, none of the wells were completed or turned to sales.

Unita Basin, South San Arroyo Prospect . We maintain 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 future activity in this prospect and the related costs were written off during 2008.

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. In January 2006, we sold 75% of our interest to Meridian Resource Corporation (“Meridian”) for approximately $4.0 million and agreed that Meridian would become the operator. As of the date of this report, Meridian has elected not to drill this prospect because of the lack of compelling discoveries by other operators in the general area, resulting in our election not to carry this as prospective acreage for us.

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.

From 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.

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, 2008, we had the following hedges in place:

	Oil - BBLS						Nat. Gas - MCF

	Barrels Per Quarter		Barrels Per Day		Price		Mcf Per Quarter		Mcf Per Day		Price

1Q 09		18,725		207	$	90.14		60,000		664	$	7.75
2Q 09		17,425		193	$	92.14		60,000		664	$	7.75
3Q 09		17,600		195	$	92.13		60,000		664	$	7.75
4Q 09		17,600		195	$	92.13		60,000		664	$	7.75

1Q 09		14,825		164	$	93.16
2Q 09		15,000		166	$	105.45
3Q 09		15,000		166	$	105.45
4Q 09		15,000		166	$	105.45

1Q 09		13,500		149	$	105.45
2Q 09		13,500		149	$	105.45
3Q 09		13,500		149	$	105.45
4Q 09		13,500		149	$	105.45

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).

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.

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.

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 eight 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.

Condensate . Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons.

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.

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.

ngl. Natural gas liquids, or liquid hydrocarbons found in association with natural gas.

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.

Proved oil and gas reserves . Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i)

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

(ii)

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

(iii)

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

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

Proved undeveloped reserves . Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves he attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Probable Reserves. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P estimate.

Possible Reserves. Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10-percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

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.

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, 2008, we had working capital of $3.7 million, including $6.1 million of cash and cash equivalents. In addition, we have $27.0 million of availability under our credit facilities, of which $21.5 million is outstanding as of March 30, 2009. As of December 31, 2008, based on our working capital, available borrowings under the credit facility and 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, 2009. 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, 2009.

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. 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, 2008, we have incurred a net loss from operations of $17,752,772. 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 on many of our prospects, 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. Part of 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 many of our property interests subjects us to a number of risks, including 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.

We have limited management and staff and will be dependent upon partnering arrangements. As of March 2009, we have eight employees, including our five executive officers. We have developed an operating strategy that involves our participation in many producing properties and exploration prospects as a non-operator. 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 eight 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. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

Any failure to meet our debt obligations would adversely affect our business and financial condition .

On September 9, 2008, we entered into $65 million of credit facilities with certain lenders named in the agreement and CIT Capital USA Inc., as administrative agent for the lenders.

As of March 30, 2009, we have $27.0 million of availability under our credit facilities, of which $21.5 million is drawn.

The credit facilities require us to satisfy certain financial covenants, including maintaining a minimum ratio of EBITDAX to interest expense, a minimum ratio of net debt to EBITDAX, a minimum ratio of consolidated current assets to consolidated current liabilities and a minimum ratio of total reserve value to debt. We are also required to enter into certain swap agreements pursuant to the terms of the credit facilities.

PRC Williston LLC, our wholly-owned subsidiary, has guaranteed the performance of all of our obligations under the CIT Capital USA credit facilities and we have collateralized our obligations under the facilities through our grant of a first priority security interest in our ownership interest in PRC Williston, subject only to certain permitted liens.

Our ability to meet debt obligations under the credit facilities will depend on the future performance of our properties, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. Our failure to service this debt could result in a default under the credit facilities, which could result in the loss of our ownership interest in PRC Williston and otherwise materially adversely affect our business, financial condition and results of operations.

Our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas. If oil and natural gas prices continue to decrease or stay at depressed levels, we may be required to take additional write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities. There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. We account for our oil and natural gas exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and stockholders’ equity.

Additional write downs could occur if oil and gas prices continue to decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. It is likely that the cumulative effect of a write-down could also negatively impact the value of our securities, including our common stock.

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 may 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 us to achieve and maintain certain financial ratio tests. There can be no assurance that we 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.

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.

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. 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.

Risks Relating to the Oil and Gas Industry

Oil and natural gas and oil prices are highly volatile and have declined significantly since mid 2008, and lower prices will negatively affect our financial condition, planned capital expenditures and results of operations. Since mid 2008, publicly quoted spot oil and natural gas prices have declined significantly from record levels in July 2008 of approximately $145.31 per Bbl (West Texas Intermediate) and $11.87 per Mcfe (WAHA) to approximately $52.38 per Bbl and $3.06 per Mcfe as of March 27, 2009. In the past, some oil and gas companies have curtailed production to mitigate the impact of low natural gas and oil prices. We may determine to shut in a portion of our production as a result of the decrease in prices. The decrease in oil and natural gas prices has had a significant impact on our financial condition, planned capital expenditures and results of operations. Further declines in oil and natural gas prices or a prolonged period of low oil and natural gas prices may materially adversely affect our financial condition, liquidity (including our borrowing capacity under our credit facilities), ability to finance planned capital expenditures and results of operations. 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.

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:

·		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.

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 NYSE Amex stock exchange market under the symbol “PRC”. As of March 27, 2009, the last reported sale price of our common stock on the NYSE-Amex was $0.25 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.

Our common stock may be delisted from the NYSE Amex and if this occurs you may have difficulty converting your investment into cash efficiently . The NYSE Amex (formerly known as the American Stock Exchange) has established certain standards for the delisting of a security from the NYSE Amex. The standards for delisting from the stock market include, among other things, common stock selling for a substantial period of time at a low price per share, if the issuer fails to effect a reverse split of such shares within a reasonable time after being notified that the stock exchange deems such action to be appropriate. Our common stock has continuously traded below $1.00 since October 2008. While we have not received any communication to date from the NYSE Amex concerning the selling price of our common shares, there can be no assurance that the NYSE Amex will take action to delist our common stock from the exchange due to the low selling price of the shares. If that were to occur, we would consider effecting a reverse split of our common stock in order to raise our share price to a level satisfactory to the NYSE Amex. However, reverse splits of thinly traded shares have, at times, resulted in declining share price after a proportional adjustment in shares price to give effect to the split. If our common stock were to be excluded from NYSE Amex, or if we elected to conduct a reverse split in order to maintain the listing, the price of our common stock and the ability of holders to sell such stock could be materially adversely affected.

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. We added additional office space of 3,166 square feet beginning in March 2009. The monthly base rental will be $5,804 and escalating to a monthly base rate of $6,200 in 2011.

Reserves

Our natural gas and crude oil reserves have been estimated as of December 31, 2008 by Cawley, Gillespie & Associates, Inc. (“CGA”), DeGolyer & MacNaughton (“DM”), W.D. Von Gonten & Co. (“VG”), and Netherland, Sewell and Associates, Inc. (“NSAI”) 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. Since January 1, 2008, we have not filed, nor were we required to file, any reports concerning our oil and gas reserves with any federal authority or agency.

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.

The following table sets forth our estimated proved reserves as of December 31, 2008.

	Proved Reserves
	2008			2007
	Developed	Undeveloped	Total	Developed	Undeveloped	Total
Crude Oil (bbls):
CGA	880,286	488,683	1,368,969	1,379,330	604,865	1,984,195
DM	476,586	476,383	952,969	143,288	242,117	385,405
VG	37,436	49,879	87,315
Total Oil (bbls):	1,394,308	1,014,945	2,409,253	1,522,618	846,982	2,369,600
Natural Gas (Boe)
CGA	85,143	0	85,143	132,102	-	132,102
DM	289,274	235,809	525,083	78,119	136,781	214,900
NSAI	50,500	48,100	98,600
Total Gas (Boe):	424,917	283,909	708,826	210,221	136,781	347,002
Total Proved Reserves (Boe)	1,819,225	1,298,854	3,118,079	1,732,839	983,763	2,716,602

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, 2008.

	2008		2007		2006
Production Volume
Natural Gas (Mcf)		341,052		151,627		20,266
Oil and Natural Gas Liquids (Bbls)		151,815		99,417		67
Average Sales Prices:
Natural Gas (per Mcf)	$	6.21	$	3.49	$	5.89
Oil (Bbls)	$	81.47	$	64.28	$	54.62
Costs of Production (per BOE)	$	25.78	$	28.16	$	13.81
DD&A (per BOE)	$	36.82	$	14.29	$	76.19

Drilling Activity

Information with regard to our drilling activities during the three years ended December 31, 2008 is set forth below.

	2008		2007		2006
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells:
Productive	25	2.45	15	2.11	9	1
Unproductive	11	2.20	6	0.93	12	2.1
Total	36	4.65	21	3.04	21	3.1
Developmental Wells:			4	1.96	0	0
Total Wells:
Productive	33	3.86	19	4.07	9	1
Unproductive	0	0	6	0.93	12	2.1
Total	33	3.86	25	5	21	3.1

Acreage

The following table summarizes by state our developed and undeveloped acreage as of December 31, 2008. The term of the undeveloped leasehold acreage ranges from three to five years.

	Developed 1				Undeveloped 2
State	Gross 3		NET 4		Gross 3		NET 4
North Dakota		15,200		6,393		3,411		1,116
Texas		9,295		873		63,821		9,203
Louisiana		1,961		518		-		-
Kentucky		-		-		74,000		4,936
Utah		-		-		20,300		17,249
New Mexico		-		-		90,300		9,030
Colorado		-		-		9,315		1,747
Totals		26,456		7,784		261,147		43,281

_________________

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.

Productive Wells

The following table summarizes by geographic area our gross and net interests in producing oil and gas wells as of December 31, 2008. 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.

	Gross Wells 2				Net Wells 3
State	Oil		Gas		Oil		Gas
North Dakota		158		0		67.9		0
Texas		36		42		3.6		4.2
Louisiana		1		1		.344		0.1
Total		195		43		71.8		4.3

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, 2008 and 2007, and the changes in quantities and standardized measure of such reserves for each of the two years then ended, see Note 14 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.

PART II

Item 5.

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

Recent Market Prices

Our common stock trades on the NYSE Amex (formerly the American Stock Exchange) under the symbol “PRC.”

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

	High		Low
2008:
First quarter	$	2.44		1.25
Second quarter		3.50		1.28
Third quarter		3.36		0.79
Fourth quarter		1.29		0.26

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

Holders

On March 2, 2009, there were approximately 1220 owners of record of our common stock.

Dividends

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. The terms of our credit facilities with CIT Capital USA, Inc. restrict our ability to pay dividends on our equity shares.

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, 2008:

	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		1,035,000	$	3.11		1,625,000
Equity compensation plans not approved by security holders		0		0		0
Total		1,035,000	$	3.11		1,625,000

Recent Sales of Unregistered Securities

We have previously disclosed by way of quarterly reports on Form 10-Q and current reports on Form 8-K filed with the SEC all sales by us of our unregistered securities during 2008.

Item 6.

SELECTED FINANCIAL DATA

Not applicable.

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 pursue interests in oil and gas properties in partnership with oil and gas companies that have exploration, development and production expertise. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team along with that of our operating partners. Our oil and gas properties are located principally in Texas, Louisiana, North Dakota, New Mexico and Kentucky.

Since the commencement of our oil and gas operations in 2005, we have been successful in creating and expanding a balanced portfolio consisting of producing properties and prospects that are geologically and geographically diverse, including producing properties, secondary enhanced oil recovery projects, and exploration prospects. This diversity provides projects with varied payout periods, helping the company remain competitive in volatile markets. We target low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningful production and reserve growth.

As of December 31, 2007, our net total proved reserves were 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. As of December 31, 2008, our estimated net total proved reserves had grown to approximately 3,118,079 boe (net of production) of which approximately 2,409,253 boe were crude oil reserves and 708,826 boe were natural gas reserves. The increase in net total proved reserves is the result of successful exploratory drilling efforts in our Cinco Terry Project in Crockett County, Texas, Surprise Prospect in Nacogdoches County, Texas and in our East Chalkley Prospect in Cameron Parish, Louisiana. From these prospects, we added approximately 931,997 boe of proved reserves net of production, which offsets a reduction of 530,520 boe of proved reserves net of production in North Dakota.

Results of Operations

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 given appropriate economic conditions. We 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. We also participate as a non-operator and evaluate each prospect based on its geological and geophysical merits and, in large part, on an operator’s track record and resources. We intend to operate certain prospects and projects in the near future in order to gain both economic and operational advantages.

For the Year Ended December 31, 2008 Compared to December 31, 2007

Revenues for the year ended December 31, 2008 totaled $15,883,441 compared to revenues of $7,020,533 for the year ended December 31, 2007. Revenue for the year ended December 31, 2008 consisted $14,486,478 of oil and gas sales,$1,196,963 of revenue from the gain on our sale of Hall Houston Exploration II, and $200,000 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. Revenue for the prior year period consisted of $6,920,533 of oil and gas sales and $100,000 of liquidated damages related to the Palo Duro acreage. Approximately 75% of the increase in revenue from oil and gas sales was to increased production and 25% was due to increase in prices.

Lease operating expenses for the year ended December 31, 2008 totaled $5,378,989, compared to lease operating expenses of $3,510,521 for the prior year period. Approximately 30% of the increase in lease operating expenses was due to the increase in the number of producing wells in our Cinco Terry Field in Crockett County, Texas, and the remainder of the increase was due to the increase in the secondary recovery efforts in North Dakota.

Exploration costs increased to $7,348,778 for the year ended December 31, 2008 from $1,767,898 during the prior year period. Exploration costs represent our drilling costs associated with dry holes. Exploration costs for 2008 include two deep wells drilled in North Dakota in our Newport Prospect as well as four shallow wells also drilled in North Dakota. We also wrote off our South San Arroyo prospect in New Mexico and our White Water prospect in Colorado.

Our expenses for impairment of oil and gas properties increased to $1,973,015 for the year ended December 31, 2008 from $95,272 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. Almost all of the impairment was related to our North Dakota properties.

Our expenses for depreciation, depletion, and accretion for the year ended December 31, 2008 totaled $7,682,293, compared to $1,781,263 for the prior year period. Approximately 50% of this increase was due to increased depletion rates because of increased capitalized costs and approximately 50% was due to increased production in the Williston Basin and the Cinco Terry Fields.

General and administrative expenses for the year ended December 31, 2008 totaled $3,964,664 compared to general and administrative expenses of $2,751,647 for the prior year period. General and administrative expenses for the years ended December 31, 2008 and December 31, 2007 included expenses of $1,589,675 and $1,117,836, respectively, for outstanding common stock options granted under our Stock Incentive Plan and common shares issued to executive officers. Without giving effect to expenses for common shares and stock options, our general and administrative expenses for the years ended December 31, 2008 and December 31, 2007 were $2,374,989 and $1,633,811, 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 and travel.

We incurred a net loss from operations of $10,464,300 for the 2008 fiscal year, compared to a net loss from operations of $2,886,068 during the prior year. The net loss from operations increased during 2008 due to increased expenses associated with lease operating expenses, exploration, impairment, and depreciation, depletion and accretion and general and administrative expenses partially offset by an increase in revenue.

During the year ended December 31, 2008, interest expense increased by $2,028,835 to $2,771,858, over the prior year period. The increase in interest expense was due to the fact that we capitalized less interest in 2008 due to less activity in the Williston Basin.

During the year ended December 31, 2008, we realized a gain on derivative contracts of $7,311,255 compared to a loss on derivative contracts of $2,458,165 during the prior year. Beginning in March 2007, we have entered into commodity derivative financial instruments for purposes of hedging our exposure to market fluctuations of oil prices. These fluctuations are driven by the change in the market prices of hedged oil and gas volumes.

We incurred a net loss to common stockholders of $7,620,740 during fiscal 2008, compared to a net loss to common stockholders of $6,050,357 for the prior year period. The increase in net loss to common stockholders was primarily the result of an increase in our exploration, impairment and depreciation expenses offset by increased revenues and gains on derivative contracts.

We generated positive cash flow from operations of $3,437,329 in fiscal 2008, compared to a positive cash flow from operations of $853,615 for fiscal 2007 due to increased revenue.

Plan of Operations

Our plan of operations for the next twelve months is to continue further exploration and development of oil and natural gas prospects that we currently own; concentrating on those with the lowest development and lifting costs. Consistent with that is our gradual structuring and staffing of our company toward becoming an operator of select properties in Texas and Louisiana. By becoming an operator, we will have more control over drilling and developmental decisions and will broaden the spectrum of exploration prospects we can consider for participation. As an operator we should reduce overall finding costs and in the future we may start to generate exploration prospects.

The continued development of our properties and prospects and the pursuit of fresh opportunities require that we maintain access to adequate levels of capital. We will strive for an optimal balance between our property portfolio and our capital structuring that will allow for growth and to the maximum benefit of our shareholders. The decisions around the balancing of capital needs and property holdings will be a challenge to us as well as all companies in the entire energy industry during this time of lowered commodity prices and an increasing complex global economic picture. As a function of balancing properties and capital, we may decide to monetize certain properties to reduce debt or to allow us to acquire interest in new prospects or producing properties that may be better suited to the current economic and energy industry environment.

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, 2009. 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, 2009. 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 $65 million in credit facilities, we are prohibited from incurring any additional debt from third parties. Our ability to obtain additional working capital through new bank lines of credit and project financing may be subject to the repayment of outstanding sums drawn from the $65 million credit facilities.

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.

Financial Condition and Liquidity

As of the date of this report, we estimate our capital budget for fiscal 2009 to be approximately $7.1 million, including:

Up to $3.1 million to be deployed for drilling in Cinco Terry.

	·	Up to $1.8 million towards operations in the Surprise Prospect.

	·	Up to $1.7 million to be used in connection with our interest in the East Chalkley Prospect and Leblanc Prospect. Approximately $500,000 to be used in connection with other prospect areas.

As of December 31, 2008, we had total assets of $61,664,868 and working capital of $6,682,370. In addition, we have available to us a $65 million in credit facilities, of which $21.5 million is outstanding as of December 31, 2008, for purposes of financing our commitments towards the drilling and development of our oil and gas 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, 2009. 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, 2009.

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 $65 million credit facilities, 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 $65 million credit facilities, 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 $65 million credit facilities. 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.

CIT Credit Facility

Series A Preferred Stock Redemption

Sale of Hall-Houston Exploration II, L.P. Partnership Interest

On September 26, 2008, we sold our 5.33% limited partner interest in Hall-Houston Exploration II, L. P. pursuant to a Partnership Interest Purchase Agreement dated September 26, 2008, as amended on September 29, 2008. The interest was purchased by a non-affiliated partnership for a cash consideration of $8.0 million and the purchaser’s assumption of the first $1,353,000 of capital calls on the limited partnership interest sold subsequent to September 26, 2008. We have agreed to reimburse the purchaser for up to $754,255 of capital calls on the limited partnership interest sold in excess of the first $1,353,000 of capital calls subsequent to September 26, 2008. We realized a net gain on the sale of the asset of $1.20 million for the quarter ending September 30, 2008, subject to future upward adjustment to the extent that some or all of the $754,255 is not called. The proceeds of the sale of the limited partnership were used to redeem the Company’s outstanding shares of Series A Preferred Stock.

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.

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, 2008 and 2007	F-2

Statements of Operations for the years ended December 31, 2008 and 2007	F-3

Statements of Shareholders' Equity for the years ended December 31, 2008 and 2007	F-4

Statements of Cash Flows for the years ended December 31, 2008 and 2007	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, 2008 and 2007, 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 audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform 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 opinion.

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, 2008 and 2007, 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 30, 2009

F-1

PETRO RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,			December 31,
	2008			2007
Assets
Current assets
Cash and cash equivalents		6,120,402			15,399,547
Accounts receivable		1,038,973			924,607
Prepaids		75,406			25,519
Derivative assets		2,944,997			-
Deferred financing costs, net of amortization of $1,513,586		-			2,378,492
Total current assets		10,179,778			18,728,165


Property and equipment
Oil and natural gas properties, successful efforts accounting
Unproved		18,562,932			24,676,434
Proved properties, net		27,264,790			18,936,428
Furniture and fixtures, net		110,499			118,354
Total property and equipment		45,938,221			43,731,216

Other assets
Investment in partnership		-			3,892,944
Derivative Assets		4,338,832			-
Deferred financing costs, net of amortization of $129,200		1,197,780			-
Deposit		10,257			10,257
Total other assets		5,546,869			3,903,201

Total Assets		61,664,868			66,362,582

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable		2,617,034			1,525,474
Accrued liabilities		106,592			210,351
Payable on sale of partnership		754,255			-
Stock payable		-			34,068
Note payable		19,527			-
Derivative liability		-			1,159,598
Short-term debt, net of discount of $2,956,206		-			11,344,136
Total current liabilities		3,497,408			14,273,627

Derivative liability		-			672,718
Revolving credit borrowings		6,500,000			-
Term loan		15,000,000			-
Asset retirement obligation		1,589,197			1,434,114
Total liabilities		26,586,605			16,380,459

Minority interest		1,384,909			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,
36,768,172 and 36,599,372 shares issued and outstanding
as of December 31, 2008 and December 31, 2007 respectively		367,682			365,994
Additional paid in capital		51,311,502			49,723,515
Accumulated deficit		(17,985,830	)		(10,365,090	)
Total shareholders' equity		33,693,354			39,724,419

Total Liabilities and Shareholders' Equity		61,664,868			66,362,582

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

F-2

PETRO RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended
	December 31
	2008			2,007
Revenue
Oil and gas sales		14,486,478		6,920,533
Other income		200,000		100,000
Gain on sale of property		1,196,963		-
		15,883,441		7,020,533
Expenses
Lease operating expenses		5,378,991		3,510,521
Exploration		7,348,778		1,767,898
Impairment of oil & gas properties		1,973,015		95,272
Depreciation, depletion and accretion		7,682,293		1,781,263
General and administrative		3,964,664		2,751,647

Total expenses		26,347,741		9,906,601

Loss from operations		(10,464,300	)	(2,886,068	)

Other income and (expense)
Interest income		188,932		171,557
Interest expense		(2,771,858	)	(743,023	)
Loss on debt extinguishment		(2,790,829	)	-
Gain (loss) on derivative contracts		7,311,255		(2,458,165	)

Loss before minority interest		(8,526,800	)	(5,915,699	)

Minority interest		1,640,466		376,270

Net loss		(6,886,334	)	(5,539,429	)

Dividend on Series A Convertible Preferred		(734,406	)	(510,928	)

Net loss attibutable to common stockholders		(7,620,740	)	(6,050,357	)

Earnings per common share
Basic and diluted		(0.21	)	(0.28	)

Weighted average number of common shares outstanding
Basic and diluted		36,714,489		21,253,995

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, 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

Preferred stock dividend											(734,406	)		(734,406	)
Restricted stock issued to employees and consultants		168,800			1,688			341,782						343,470
Stock options to employees								1,246,205						1,246,205
Net loss											(6,886,334	)		(6,886,334	)
Balance, December 31, 2008		36,768,172			367,682			51,311,502			(17,985,830	)		33,693,354

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
	2008			2007

Cash flows from operating activities
Net loss		(6,886,334	)		(5,539,429	)
Adjustments to reconcile net income to net cash provided by operating activities:
Minority interest		(1,640,466	)		(376,270	)
Depletion, depreciation, and accretion		7,682,293			1,781,263
Amortization included in interest expense		1,737,458			468,938
Amortization of insurance expense		-			125,972
Impairment		1,973,015			95,272
Gain on asset retirement obligation		(16,837	)		-
Dry hole costs		7,140,013			1,310,988
Issuance of common stock and stock options for services		1,589,675			1,117,836
Gain on sale of assets		(1,196,963	)		-
Loss on extinguishment of debt		2,790,829			-
Unrealized (gain) loss on derivative contracts		(9,116,145	)		1,832,316
Changes in operating assets and liabilities:
Accounts receivable and accrued revenue		(114,366	)		(833,263	)
Prepaid expenses		(49,887	)		-
Accounts payable		(631,563	)		626,873
Accrued expenses		176,607			243,119
Net cash provided by operating activities		3,437,329			853,615

Cash flows from investing activities
Capital expenditures		(16,222,790	)		(14,266,262	)
Proceeds from sale of assets		7,843,962			-
Acquisition of Williston Basin		-			(14,097,855	)
Investment in partnership		(1,999,800	)		(1,599,840	)
Net cash used in investing activities		(10,378,628	)		(29,963,957	)

Cash flows from financing activities
Proceeds from sale of common stock, net		-			27,971,014
Issuance of preferred stock					2,000,000
Cost to issue preferred stock		-			(14,705	)
Financing costs		(1,326,980	)		(3,892,078	)
Payments for debt refinancing		(144,565	)		-
Redemption of prefered stock		(7,966,735	)		-
Proceeds from debt refinancing		5,128,947			-
Proceeds from note payable		4,225,348			28,534,442
Payments of note payable		(2,253,861	)		(14,373,988	)
Net cash provided by (used in) financing activities		(2,337,846	)		40,224,685

Net increase (decrease) in cash and cash equivalents		(9,279,145	)		11,114,343
Cash and cash equivalents, beginning of period		15,399,547			4,285,204

Cash and cash equivalents, end of period		6,120,402			15,399,547

Supplemental disclosure of cash flow information
Cash paid for interest		1,554,484			1,944,388
Cash paid for federal income taxes		-			-

Non-cash transactions
Common stock issued in acquisition of Williston Basin properties		-			10,723,274
Royalty 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
Refinancing of Petrobridge loan		16,239,152			-
Capitalized interest in oil and gas properties		1,080,177			1,675,802
Property and equipment included in accounts payable		1,527,440			681,731

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

F-5

NOTE 1 - ORGANIZATION AND NATURE OF OPERATIONS

Petro Resources Corporation is an oil and gas exploration and production company incorporated in June 1997 in the State of Delaware.

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.

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. Financial instruments that potentially subject the Company to concentration of credit risk consist primarily of cash deposits. Accounts at each financial institution are insured by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000. At December 31, 2008, the Company had cash deposits in excess of FDIC insured limits at various financial institutions.

Deferred financing costs .

In connection with debt financings in 2008, Petro Resources paid $1,326,980 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 the straight line method when the debt is in the form of a line of credit. The total amortization of $129,200 was all incurred in 2008.

F-6

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 derivative contracts 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

The Company 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, the Company recognized a non-cash, pre-tax charge against earnings of $1,973,015 and $95,272 in 2008 and 2007, respectively.

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 property 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.

F-7

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.

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 Property and Equipment

Property 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 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. 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.

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 property 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.

F-8

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 20% 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, 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.

Revenue Recognition

Revenues associated with sales of crude oil, natural gas, natural gas liquids and petroleum 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.

Share Based Compensation

The Company accounts for share-based compensation in accordance with the provisions of Statement of Financial Accounting Standards No. FAS 123(R), Share Based Payment requires companies to estimate the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and employee stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. We estimate the fair value of each share-based award using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards and the estimated volatility of our stock price.

Income Taxes

The Company 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.

On January 1, 2007, the Company adopted the provisions of FIN 48, Accounting for Uncertainty in Income Taxes, and (“FIN 48”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under FIN 48, we recognize tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards. As of December 31, 2008 and 2007, the Company has determined that no liability is required to be recognized due to adoption of FIN48.

F-9

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.

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, 2008 and 2007, 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.

On December 31, 2008, the Securities and Exchange Commission (SEC) issued the final rule, “Modernization of Oil and Gas Reporting” (“Final Rule”). The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and technological advances. Revised requirements in the Final Rule include, but are not limited to:

· Oil and gas reserves must be reported using a 12-month average of the closing prices on the first day of each of such months, rather than a single day year-end price:

· Companies will be allowed to report, on a voluntary basis, probable and possible reserves, previously prohibited by SEC rules; and

· Easing the standard for the inclusion of proved undeveloped reserves (PUDs) and requiring disclosure of information indicating any progress toward the development of PUDs.

We are currently evaluating the potential impact of adopting the Final Rule. The SEC is discussing the Final Rule with the FASB and IASB staffs to align accounting standards with the Final Rule. These discussions may delay the required compliance date. Absent any change in such date, we will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009. Voluntary early compliance is not permitted.

In March 2008, the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging Activities. SFAS 161 is effective beginning January 1, 2009 and required entities to provide expanded disclosures about derivative instruments and hedging activities including (1) the ways in which an entity uses derivatives, (2) the accounting for derivatives and hedging activities, and (3) the impact that derivatives have (or could have) on an entity’s financial position, financial performance, and cash flows. SFAS 161 requires expanded disclosures and does not change the accounting for derivatives. Petro is currently evaluating the impact of SFAS 161, but we do not expect the adoption of this standard to have a material impact on our financial results.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements - an amendment of Accounting Research Bulletin No. 5 1 ("SFAS 160"), which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent's ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that require disclosure that clearly identifies and distinguishes between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 is effective on January 1, 2009 and the Company is currently evaluating the potential impact, if any, of the adoption of SFAS 160 on its consolidated financial statements.

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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 (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. Following the election of the Fair Value Option for certain financial assets and liabilities, the Company would report unrealized gains and losses due to changes in fair value in earnings at each subsequent reporting date. The Company adopted SFAS 159 effective January 1, 2008 which did not have a material impact on the Company’s operating results, financial position or cash flows as the Company did not elect the Fair Value Option for any of its financial assets or liabilities.

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. We have partially adopted FAS 157 as of January 1, 2008 except for those non-recurring measurements for non-financial assets and non-financial liabilities subject to the partial deferral in FASB Statement of Position No. 157-2, Partial Deferral of the Effective Date of Statement 157,” (“FSP 157-2”). The adoption of FAS 157 did not have an impact on the Company’s consolidated financial position or operating results. FSP 157-2 delays the effective date of FAS 157 from fiscal years beginning after November 15, 2007 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

Reclassification of Prior-Year Balances

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

NOTE 2 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Effective January 1, 2008, the Company adopted the provisions of SFAS No. 157, Fair Value measurements, for all financial instruments. SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

●	Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets

●	Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable

●	Level 3 — Significant inputs to the valuation model are unobservable

The following describes the valuation methodologies we use to measure financial instruments at fair value.

Derivative Instruments

At December 31, 2008, we had commodity derivative financial instruments in place that do not qualify for hedge accounting under SFAS 133. Therefore, the changes in fair value subsequent to the initial measurement are recorded in income. Although our derivative instruments are valued using public indexes, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, our derivative liabilities have been classified as Level 2.

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The follow table provides a summary of the fair value of our derivative liabilities measured on a recurring basis under SFAS 157:

	Fair value measurements on a recurring basis December 31, 2008
	Level 1		Level 2		Level 3
Assets
Commodity derivatives	$	-	$	7,283,829	$	-
Liabilities
Commodity derivatives	$	-	$	-	$	-

NOTE 3 - FINANCIAL INSTRUMENTS AND DERIVATIVES

We entered into commodity derivative financial instruments intended to hedge our exposure to market fluctuations of oil prices. As of December 31, 2008, we had commodity swaps for the following oil volumes:

	Barrels per quarter		Barrels per day		Price per barrel

2009
First quarter		9,725		108	$	71.76
Second quarter		8,325		91	$	72.62
Third quarter		8,400		91	$	72.55
Fourth quarter		8,400		91	$	72.55

2010
First quarter		14,825		165	$	93.50
Second quarter		15,000		165	$	105.45
Third quarter		15,000		163	$	105.45
Fourth quarter		15,000		163	$	105.45

2011
First quarter		13,500		150	$	105.45
Second quarter		13,500		148	$	105.45
Third quarter		13,500		147	$	105.45
Fourth quarter		13,500		147	$	105.45

As of December 31, 2008, the fair value of the above commodity swaps $4,792,629 .

On June 5, 2008, the Company purchased a floor at $110 per barrel for 100 bbls per day for the calendar year 2009 for a price of $363,175. As of December 31, 2008 the fair value of the floor was $2,052,620.

On October 6, 2008, the Company purchased a floor at $7.75 per MCF for 20,000 MCF per month for the calendar year 2009 for a price of $200,400. As of December 31, 2008 the fair value of the floor was $438,580.

During the year ended December 31, 2008, we incurred a gain of $7,311,255 related to derivative contracts. Included in this gain was $1,241,315 of realized losses related to settled contracts, and $8,552,570 of unrealized gains related to unsettled contracts. Unrealized gain and losses are based on the changes in the fair value of derivative instruments covering positions beyond December 31, 2008.

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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)

The 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	)
Net	$	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, 2007, are as follows:

	Year ended December 31, 2007
Revenue	$	7,615,876
Net loss		(6,353,774	)
Net loss per common share	$	(.30	)

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.

F-13

On September 26, 2008, the Company sold its 5.33% limited partner interest in Hall-Houston Exploration II, L. P. pursuant to a Partnership Interest Purchase Agreement dated September 26, 2008, as amended on September 29, 2008. The interest was purchased by a non-affiliated partnership for a cash consideration of $8.0 million and the purchaser’s assumption of the first $1,353,000 of capital calls subsequent to September 26, 2008. The Company agreed to reimburse the purchaser for up to $754,255 of capital calls in excess of the first $1,353,000. The Company’s net gain on the sale of the asset of is subject to future upward adjustment to the extent that some or all of the $754,255 is not called. As of and for the year ended December 31, 2008, the Company reported a net gain on the sale of the above interest of $1,113,000 and recognized the liability for the capital calls. The proceeds of the sale of the limited partnership were used to redeem the Company’s outstanding shares of Series A Preferred Stock.

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.

	2008			2007
Asset retirement obligation at beginning of period	$	1,434,114		$	30,653
Purchase		-			1,250,323
Liabilities incurred		93,154			42,407
Liabilities settled		(17,012)			-	)
Accretion expense		138,772			111,301
Revisions in estimated liabilities		(59,831	)		(570	)
Asset retirement obligation at end of period	$	1,589,197		$	1,434,114

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, 2008 and 2007, there were no amounts due related to the production floor payments.

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NOTE 8 - NOTES PAYABLE

In connection with the Williston Basin acquisition, we entered into a $75 million credit agreement (the “Credit Facility” or “Petrobridge Note”) 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.

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.

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 note was fully paid on February 1, 2008.

On September 9, 2008, the Company entered into (1) a $50 million Credit Agreement (the "Credit Agreement") with certain lenders named in the agreement and CIT Capital USA Inc., as administrative agent for the lenders and (2) a $15 million Second Lien Term Loan Agreement (the "Second Lien Term Loan Agreement") with certain lenders named in the agreement and CIT Capital USA Inc., as administrative agent for the lenders.

F-15

Borrowings under the Credit Agreement bear interest, at the Company's option, at either a fluctuating base rate or a rate equal to LIBOR plus, in each case, a margin determined based on the Company's utilization of the borrowing base. If an event of default occurs and is continuing, the lenders may increase the interest rate then in effect by an additional 2% per annum. The Credit Agreement contains covenants that, among others things, restrict the ability of the Company to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) acquire other companies or assets; (4) dispose of all or substantially all of its assets or enter into mergers, consolidations or similar transactions; (5) make restricted payments; (6) enter into transactions with affiliates; and (7) make capital expenditures. The Credit Agreement also requires the Company to satisfy certain financial covenants, including maintaining (1) a ratio of EBITDAX to Interest Expense (as each term is defined in the Credit Agreement) of not less than 2.5:1.0; (2) a ratio of Net Debt (as such term is defined in the Credit Agreement) to EBITDAX of not more than (a) 4.5:1.0 for the fiscal quarters ending December 31, 2008, March 31, 2009, June 30, 2009 and September 30, 2009, and (b) 3.5:1.0 for each fiscal quarter ending thereafter; and (3) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0:1.0. The Company is also required to enter into certain swap agreements pursuant to the terms of the Credit Agreement.

PRC Williston LLC, the Company's wholly owned subsidiary ("PRC Williston"), has guaranteed the performance of all of the Company's obligations under the Credit Agreement and related agreements pursuant to a Guaranty and Collateral Agreement dated as of September 9, 2008 (the "Guaranty and Collateral Agreement"). Subject to certain permitted liens, the Company's obligations have been secured by the grant of a first priority lien on no less than 80% of the value of the Company's and PRC Williston's existing and to-be-acquired oil and gas properties and the grant of a first priority security interest in related personal property of the Company and PRC Williston. The Company has also granted a first priority security interest in its ownership interest in PRC Williston, subject only to certain permitted liens.

The Second Lien Term Loan Agreement provides for a $15 million second lien term loan facility. All term loans available under the second lien term loan facility were advanced to the Company on September 9, 2008 and were used to refinance existing debt. The maturity date of the Second Lien Term Loan Agreement is September 9, 2012. Under certain circumstances, the Company is permitted to repay the term loans prior to the maturity date; however, any payments made on or prior to September 9, 2009 are subject to a prepayment penalty equal to 2% of the amount prepaid, and any payments made after September 9, 2009 but on or before September 9, 2010 are subject to a prepayment penalty equal to 1% of the amount prepaid.

Borrowings under the Second Lien Term Loan Agreement bear interest, at the Company's option, at either a fluctuating base rate plus 6.50% per annum or a rate equal to LIBOR plus 7.50% per annum. If an event of default occurs and is continuing, the lenders may increase the interest rate then in effect by an additional 2% per annum. The Second Lien Term Loan Agreement contains covenants that, among others things, restrict the ability of the Company to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) acquire other companies or assets; (4) dispose of all or substantially all of its assets or enter into mergers, consolidations or similar transactions; (5) make restricted payments; (6) enter into transactions with affiliates; and (7) make capital expenditures. The Second Lien Term Loan Agreement also requires the Company to satisfy certain financial covenants, including maintaining (1) a ratio of Total Reserve Value to Debt (as each term is defined in the Second Lien Term Loan Agreement) of not less than 1.75:1.0; and (2) a ratio of Net Debt to EBITDAX (as each term is defined in the Second Lien Term Loan Agreement) of not more than (a) 4.5:1.0 for the fiscal quarters ending December 31, 2008, March 31, 2009, June 30, 2009 and September 30, 2009, and (b) 4.0:1.0 for each fiscal quarter ending thereafter.

PRC Williston LLC has guaranteed the performance of all of the Company's obligations under the Second Lien Term Loan Agreement and related agreements pursuant to a Second Lien Guaranty and Collateral Agreement dated as of September 9, 2008 (the " Second Lien Guaranty and Collateral Agreement"). Subject to certain permitted liens (including, without limitation, the liens and security interests granted in connection with the Credit Agreement referenced above), the Company's obligations under the Second Lien Term Loan Agreement have been secured by the grant of a first priority lien on no less than 80% of the value of the Company's and PRC Williston's existing and to-be-acquired oil and gas properties and the grant of a first priority security interest in related personal property of the Company and PRC Williston. The Company has also granted a first priority security interest in its ownership interest in PRC Williston, subject only to certain permitted liens (including, without limitation, the security interest granted in connection with the Credit Agreement).

F-16

Under the amended Credit Agreement, the Company must have (A) a ratio of EBITDAX to Interest Expense (as each term is defined in the Credit Agreement) of not less than 2.0:1.0 for the first and second fiscal quarters of 2009, 2.25:1.0 for the third and fourth fiscal quarters of 2009, and 2.5:1.0 for each fiscal quarter thereafter; (B) a ratio of Net Debt (as such term is defined in the Credit Agreement) to EBITDAX of not more than 6.5:1.0 for the fiscal quarters of 2009, 6.0:1.0 for the fiscal quarters of 2010, and 5.0:1 for each fiscal quarter thereafter; and (C) a ratio of First Lien debt to EBITDAX of not more than 2.75:1.0 for each fiscal quarter. Borrowings under the Credit Agreement bear interest, at our option, at either a fluctuating base rate or a rate equal to LIBOR (with a LIBOR floor of 2.50%) plus, in each case, a margin determined based on our utilization of the borrowing base. The amendment includes an increase in the margin of 50 basis points.

Under the amended Second Lien Term Loan Agreement, the Company must have a ratio of Net Debt to EBITDAX (as each term is defined in the Second Lien Term Loan Agreement) of not more than 6.5:1.0 for the fiscal quarters of 2009 and 2010 and 5.5:1 for the fiscal quarters of 2011 each fiscal quarter ending thereafter. Borrowings under the Second Lien Term Loan Agreement bear interest, at our option, at either a fluctuating base rate plus 6.50% per annum or a rate equal to LIBOR (with a LIBOR floor of 2.50%) plus 7.50% per annum.

The Company incurred approximately $1.3 million of deferred financing cost on the above notes and on September 9 and October 14, 2008 , the Company borrowed $6.5 million by drawing down $15 million on its Second Lien Term Loan Agreement and $6.5 million on its Credit Agreement. The Company then paid off the Petrobridge Note of $16.2 million and also incurred $2.8 million of debt extinguishment costs. The debt extinguishment costs consisted principally of the write off of the note discount and deferred financing costs related to the Petrobridge note.

On April 1, 2008 Petro Resources signed a promissory note with a finance company to finance its various insurance policies. The interest rate on the note is 4.057% with payments of $19,593 per month beginning May 1, 2008 and the final payment due January 1, 2009. The note is secured by the insurance policies. At December 31, 2008, the outstanding balance on the note was $19,527.

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.

	2008		2007
Minority interest at beginning of period	$	3,025,375	$	3,401,645
Loss to minority interest		(1,640,466)		(376,270	)
Minority interest at end of period	$	1,384,909	$	3,025,375

F-17

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 shares 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.

Petro Resources has cancelled both the returned common shares and the warrants. The Series A Preferred Stock is convertible into Petro Resources’ common stock 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, stock 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 will increase to 15% on April 3, 2008. Dividends are payable quarterly in cash or, at Petro Resources’ option, in additional shares of Series A Preferred Stock. The Series A Preferred Stock is entitled to vote with the common stock on an as converted basis. If Petro Resources is liquidated, each outstanding share of Series A Preferred Stock will be entitled to a liquidation payment in an 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 the holder had converted to common stock immediately prior to the liquidation event, plus any accrued and unpaid dividends. Petro Resources is required (Mandatory Redemption) 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. Petro Resources has the option to redeem the Series A Preferred Stock at any time, subject to 30 days prior written notice, at the same redemption price. Petro Resources also provided the Touradji funds with registration rights requiring that Petro Resources use its reasonable best efforts to file a registration statement with the SEC by April 30, 2007 for purposes of registering the resale of the shares of common stock underlying the Series A Preferred Stock and the 240,000 warrants still held by the Touradji funds. Petro Resources filed a registration statement relating to the Touradji funds’ shares of common stock on October 18, 2007. There were no penalties associated with the Registration Rights.

On September 26, 2008, the Company redeemed 2,563,712 shares of the Company's outstanding Series A Preferred Stock at an aggregate redemption price of $7,966,735. The shares were held by investment funds managed by Touradji Capital Management. Pursuant to the terms of the Preferred Stock Purchase Agreement, the Company was required to redeem all Series A Preferred Stock no later than October 2, 2008. After giving effect to the redemption, there are no shares of Series A Preferred Stock outstanding at December 31, 2008.

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, 2008 and 2007.

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.

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-18

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.

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.

On January 9, 2008 we granted 200,000 stock options to our President. The options have an exercise price of $2.00 per share. Fifty thousand options vested on January 9, 2008 and the remaining 150,000 options vest annually on January 10, 2009, 2010 and 2011. The stock options have a 5 year term expiring on January 10, 2013. The options were valued using the Black-Sholes model with the following assumption: $2.15 quoted stock price; $2.00 exercise price; 104.83% volatility; 3.25 year estimated life; zero dividend; 2.69% discount rate. The fair value of these options was $293,364.

Also, on January 9, 2008 we granted 10,000 stock options to our Director of Information Services. The options have an exercise price of $2.00 per share. Twenty five hundred options vested on January 10, 2008 and the remaining 7,500 options will vest annually on January 10, 2009, 2010 and 2011. The stock options have a 5 year term expiring on January 10, 2013. The options were valued using the Black-Sholes model with the following assumption: $2.15 quoted stock price; $2.00 exercise price; 104.83% volatility; 3.25 year estimated life; zero dividend; 2.69% discount rate. The fair value of these options was $14,668.

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 the 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 January 9, 2008, we granted 100,000 shares of restricted common stock to our President. These common shares vest at 25,000 immediately and 25,000 each on January 10, 2009, 2010 and 2011. These shares were valued at $2.15 per share, based on the quoted market value on the date of grant, and $107,500 of expense was recognized as of December 31, 2008. The remaining $107,500 will be recognized over the remaining service term.

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 the remaining shares vest annually at 30,000 shares annually on March 1, 2009, 2010 and 2011. These shares were valued at $1.70 per share, based on the quoted market value on the date of grant, and $119,000 of expense was recognized as of December 31, 2008. The remaining $102,000 will be recognized over the remaining service term.

Petro Resources recognized stock compensation expense of $1,589,675 and $1,117,836 for the year ended December 31, 2008 and 2007 respectively.

F-19

A summary of option activity for the year ended December 31, 2008 is presented below:

	Shares			Weighted- Average Exercise Price

Outstanding at December 31, 2007		1,125,000		$	3.68
Granted		310,000			1.90
Exercised, forfeited, or expired		(400,000	)		3.80
Outstanding at December 31, 2008		1,035,000			3.11

Exercisable at December 31, 2007		550,000			3.74
Exercisable at December 31, 2008		902,500		$	3.56

A summary of Petro Resources non-vested options as of December 31, 2008 is presented below.

Non-vested Options	Shares
Non-vested at December 31, 2007		575,000
Granted		310,000
Vested		(352,500	)
Forfeited		(400,000)
Non-vested at December 31, 2008		132,500

Total unrecognized compensation cost related to non-vested options granted under the Plan was $309,700and $1,334,530 as of December 31, 2008 and 2007 respectively. The cost at December 31, 2008 is expected to be recognized over a weighted-average period of 1.18 years. The aggregate intrinsic value for options was $0; and the weighted average remaining contract life was 2.9 years.

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.

The assumptions used in the fair value method calculation for the year ended December 31, 2008 and 2007 are disclosed in the following table:

	Year Ended December 31,
	2008 (1)		2007

Weighted average value per option granted during the period (2)	$	1.36	$	1.77
Assumptions (3) :
Stock price volatility		104-105%		110-119%
Risk free rate of return		1.87-2.69%		4.54-5.0%

Expected term	3.25 years		2.5-5.0 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.

F-20

A summary of warrant activity for the year ended December 31, 2008 is presented below:

	Shares	Weighted- Average Exercise Price

Outstanding at December 31, 2007	6,838,962	$	2.15
Granted	-		-
Exercised, forfeited, or expired	-		-
Outstanding at December 31, 2008	6,838,962	$	2.15

Exercisable at December 31, 2007	6,838,962	$	2.15
Exercisable at December 31, 2008	6,838,962	$	2.15

The aggregate intrinsic value for warrants was $0; and the weighted average remaining contract life was 1.91 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 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.

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:

	2008		2007
Computed at U.S. statutory rate at 34%	$	(2,341,354)	$	(1,883,407	)
Permanent differences		543,890		383,620
Changes in valuation allowance		1,797,464		1,499,787
Total	$	0	$	0

F-21

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	$	13,460,116		$	2,513,904
Derivatives		-			622,987
Less valuation allowance		(4,154,379	)		(1,094,375	)
		9,305,737			2,042,516

Deferred tax liabilities:
Oil and gas properties:		(7,020,851	)		(2,042,516
Derivatives		(2,284,886	)		-
		(9,305,737)			(2,042,516 )
	$	-		$	-

At December 31, 2008, Petro had net operating loss carryforwards for federal income tax purposes of approximately $39,588,575 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 2028.

NOTE 14 - 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:

	2008			2007
Unproved oil and gas properties	$	18,562,932		$	24,676,434
Proved oil and gas properties		39,414,361			21,606,881
		57,977,293			46,283,315
Accumulated depletion, depreciation and impairment		(12,149,571	)		(2,670,453	)
	$	45,827,722		$	43,612,862

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

	2008		2007
Purchase of non-producing leases	$	1,410,023	$	16,791,029
Purchase of producing properties		0		4,551,382
Exploration costs		5,796,608		3,081,058
Development costs		11,607,005		16,704,232
Asset retirement obligation		93,153		1,403,461
	$	18,906,789	$	42,531,162

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-22

Total Proved Reserves

	Crude oil and Condensate (Thousands of Barrels)			Natural Gas (Millions of Cubic Feet)
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
Extensions, discoveries and other additions		698.0		2,655.9
Revisions of previous estimates		(506.6)		(143.8)
Production		(151.8)		(341.1)
Balance December 31, 2008		2,409.3		4,253.0

Developed reserves, included above
December 31, 2007	1,411.8	1,069.9
December 31, 2008	1,394.3	2,549.5

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.

	2008			2007
Cash inflows	$	109,100,043		$	208,181,173
Production costs		(48,971,580	)		(76,758,323	)
Development costs		(15,341,803	)		(12,312,808	)
Income tax expense		-			(35,384,592	)
10 percent discount rate		(23,742,386	)		(43,613,756	)
Discounted future net cash flows	$	21,044,274		$	40,111,694

Changes in Standardized Measure of Discounted Future Cash Flows

	2008			2007
Beginning balance		40,111,694			579,836
Purchases		-			24,039,320
Extensions, discoveries and improved recoveries		10,334,289			26,551,353
Sales of oil and gas produced		(9,107,489	)		(3,410,012	)
Development cost incurred during the year		8,738,286			3,129,601
Changes in estimated development costs		(9,458,282	)		(9,066,693
Net changes in prices and production costs		(35,731,111	)		10,293,567
Revisions of previous quantity estimates		(4,806,546	)		(26,218
Accretion of discount		4,011,169			2,230,129
Net change in income taxes		16,952,264			(14,209,189
Ending balance		21,044,274			40,111,694

F-23

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not 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, 2008, our disclosure controls and procedures are designed at a reasonable assurance level and 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 2008 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, 2008. 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.

Item 9B.

OTHER INFORMATION

None.

PART III

Except as set forth below, the information required by Items 10 through 14 is set forth under the captions “Election of Directors,” “Ratification of Independent Registered Public Accounting Firm,” “Management,” “Executive Compensation,” “Principal Stockholders” and “Certain Transactions” in Petro Resources Corporation’s definitive proxy statement for its 2009 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 or 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.

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 Petro Resource Corporation 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
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 Petro Resource Corporation 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 Petro Resource Corporation 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

10.19 (8)		First Amendment dated May 13, 2008 to Credit Agreement dated February 16, 2007 between PRC Williston LLC and D.B. Zwirn Special Opportunities Fund, L.P., as administrative agent
10.20 (9)		Credit Agreement dated as of September 9, 2008 among Petro Resources Corporation, CIT Capital USA Inc., as administrative agent, and the lenders party thereto
10.21 (9)		Second Lien Term Loan Agreement dated as of September 9, 2008 among Petro Resources Corporation, CIT Capital USA Inc., as administrative agent, and the lenders party thereto
10.22 (9)		Guaranty and Collateral Agreement dated as of September 9, 2008 among Petro Resources Corporation, PRC Williston LLC, and CIT Capital USA Inc., as administrative agent
10.23 (9)		Second Lien Guaranty and Collateral Agreement dated as of September 9, 2008 among Petro Resources Corporation, PRC Williston LLC, and CIT Capital USA Inc., as administrative agent
10.24 (10)		Partnership Interest Purchase Agreement dated September 26, 2008, as amended on September 29, 2008, between Petro Resources Corporation and PRC HHEP II, LP
10.25		Employment Agreement dated May 27, 2008 between Petro Resources Corporation and Wayne P. Hall.*
10.26		Employment Agreement dated May 27, 2008 between Petro Resources Corporation and Donald L. Kirkendall.*
10.27		Employment Agreement dated May 27, 2008 between Petro Resources Corporation and Harry Lee Stout. *
10.28		Employment Agreement dated May 27, 2008 between Petro Resources Corporation and James W. Denny. *
10.29		Employment Agreement dated May 27, 2008 between Petro Resources Corporation and Allen R. McGee. *
10.30		First Amendment to Credit Agreement dated March 19, 2009 among Petro Resources Corporation, CIT Capital USA Inc., as administrative agent, and the lenders party thereto
10.31		First Amendment to Second Lien Term Loan Agreement dated March 19, 2009 among Petro Resources Corporation, CIT Capital USA Inc., as administrative agent, and the lenders party thereto
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
23.4		Consent of Netherland, Sewell and Associates, Inc.
23.5		Consent of W.D. Von Gonten & Co.
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 Petro Resources Corporation’s quarterly report on Form 10-QSB filed on August 14, 2007.
(7)	Incorporated by reference from Petro Resources Corporation’s Amendment No. 1 to Registration Statement on Form SB-2 filed on September 21, 2007.
(8)	Incorporated by reference from the Petro Resources Corporation’s quarterly report on Form 10-Q filed on May 15, 2008.
(9)	Incorporated by reference from Petro Resources Corporation’s current report on Form 8-K filed on September 11, 2008.
(10)	Incorporated by reference from Petro Resources Corporation’s quarterly report on Form 10-Q filed on November 13, 2008.

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, 2009	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	March 31, 2009
Wayne P. Hall	Chief Executive Officer (Principal Executive Officer)

/s/ Harry Lee Stout	Executive Vice President and	March 31, 2009
Harry Lee Stout	Chief Financial Officer (Principal Financial Officer)

/s/ Allen R. McGee	Chief Accounting Officer	March 31, 2009
Allen R. McGee	(Principal Accounting Officer)

/s/ Donald L. Kirkendall	Director	March 31, 2009
Donald L. Kirkendall

/s/ J. Raleigh Bailes, Sr.	Director	March 31, 2009
J. Raleigh Bailes, Sr.

/s/ Brad Bynum	Director	March 31, 2009
Brad Bynum

/s/ Gary L. Hall	Director	March 31, 2009
Gary L. Hall

/s/ Joe L. McClaugherty	Director	March 31, 2009
Joe L. McClaugherty

/s/ Steven A. Pfeifer	Director	March 31, 2009
Steven A. Pfeifer