PETRO RESOURCES CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
Note 1—Basis of Presentation
The accompanying unaudited interim financial statements of Petro Resources Corporation have been prepared in accordance with accounting principles generally accepted in the United States of America and rules of the Securities and Exchange Commission, and should be read in conjunction with the audited financial statements and notes thereto contained in Petro Resource’s annual report on Form 10-K for the year ended December 31, 2007 filed with the SEC on March 31, 2008. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the consolidated financial statements which would substantially duplicate the disclosure contained in the audited financial statements as reported in the 2007 annual report on Form 10-K have been omitted.
Certain prior period balances have been reclassified to conform to the current period presentation.
New accounting pronouncements
In March 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 161, Disclosures about Derivative Instruments and Hedging Activities –an amendment of SFAS 133. SFAS 161 seeks to improve financial reporting for derivative instruments and hedging activities by requiring enhanced disclosures regarding the impact on financial position, financial performance, and cash flows. To achieve this increased transparency, SFAS 161 requires: (1) the disclosure of the fair value of derivative instruments and gains and losses in a tabular format; (2) the disclosure of derivative features that are credit risk-related; and (3) cross-referencing within the footnotes. SFAS 161 is effective for us on January 1, 2009. We are in the process of evaluating the new disclosure requirements under SFAS 161.
In September 2006, the FASB issued SFAS 157, Fair Value Measurements, as amended in February 2008 by FASB Staff Position (“FSP”) FAS 157-2, Effective Date of FASB Statement No. 157. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. FSP FAS 157-2 defers the effective date of SFAS 157 for all nonfinancial assets and liabilities, except those items recognized or disclosed at fair value on an annual or more frequently recurring basis, until January 1, 2009. As such, we partially adopted the provisions of SFAS 157 effective January 1, 2008. The partial adoption of this statement did not have a material impact on our financial statements. We expect to adopt the remaining provisions of SFAS 157 beginning in 2009. We do not expect this adoption to have a material impact on our financial statements.
In February 2007, FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities–including an Amendment of FASB Statement No. 115. This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective; however the amendment to SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, applies to all entities with available-for-sale securities. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. We have adopted this statement as of January 1, 2008. The adoption created no impact to our financial statements.
PETRO RESOURCES CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
In December 2007, the FASB issued SFAS 141R, Business Combinations. SFAS 141R continues to require the purchase method of accounting to be applied to all business combinations, but it significantly changes the accounting for certain aspects of business combinations. Under SFAS 141R, an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition-date fair value with limited exceptions. SFAS 141R will change the accounting treatment for certain specific acquisition related items including: (1) expensing acquisition related costs as incurred; (2) valuing noncontrolling interests at fair value at the acquisition date; and (3) expensing restructuring costs associated with an acquired business. SFAS 141R also includes a substantial number of new disclosure requirements. SFAS 141R is to be applied prospectively to business combinations for which the acquisition date is on or after January 1, 2009. We expect SFAS 141R will have an impact on our accounting for future business combinations once adopted but the effect is dependent upon the acquisitions that are made in the future.
In December 2007, the FASB issued SFAS 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS 160 establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary (minority interest) is an ownership interest in the consolidated entity that should be reported as equity in the Consolidated Financial Statement and separate from the parent company’s equity. Among other requirements, this statement requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the Consolidated Statement of Operations, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. This statement is effective for us on January 1, 2009. We are still in the process of evaluating the impact that SFAS 160 will have on our Consolidated Financial Statements.
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 June 30, 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.
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 June 30, 2008 | |
| | | Level 1 | | | Level 2 | | | Level 3 | |
| Assets | | | | | | | | | | | | |
| Commodity derivatives – floor | | $ | - | | | $ | 259,599 | | | $ | - | |
| Liabilities | | | | | | | | | | | | |
| Commodity derivatives | | $ | - | | | $ | 3,980,137 | | | $ | - | |
PETRO RESOURCES CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
Note 3 —Derivative Financial Instruments
We entered into commodity derivative financial instruments intended to hedge our exposure to market fluctuations of oil prices. As of June 30, 2008, we had commodity swaps for the following oil volumes:
| | | Barrels per quarter | | | Barrels per day | | | Price per barrel | |
| 2008 | | | | | | | | | |
| Third quarter | | | 12,843 | | | | 140 | | | | $71.66 | |
| Fourth quarter | | | 9,200 | | | | 100 | | | | $65.70 | |
| | | | | | | | | | | | | |
| 2009 | | | | | | | | | | | | |
| First quarter | | | 8,225 | | | | 91 | | | | $65.62 | |
| Second quarter | | | 6,825 | | | | 75 | | | | $65.40 | |
| Third quarter | | | 6,900 | | | | 75 | | | | $65.40 | |
| Fourth quarter | | | 6,900 | | | | 75 | | | | $65.40 | |
| | | | | | | | | | | | | |
| 2010 | | | | | | | | | | | | |
| First quarter | | | 4,425 | | | | 49 | | | | $65.40 | |
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 June 30, 2008 the fair value of the floor was $259,599.
During the six months ended June 30, 2008, we incurred a loss of $3,463,650 related to derivative contracts. Included in this loss was $1,212,254 of realized losses related to settled contracts, $103,576 of losses related to the floor and $2,147,820 of unrealized losses related to unsettled swap contracts. Unrealized losses are based on the changes in the fair value of derivative instruments covering positions beyond June 30, 2008.
Note 4 —Asset Retirement Obligations
We recorded the following activity related to the ARO liability for the six months ended June 30, 2008:
| Liability for asset retirement obligation as of December 31, 2007 | | $ | 1,434,114 | |
| Liabilities settled and divested | | | - | |
| Additions-Drilling | | | 20,475 | |
| Accretion expense | | | 68,781 | |
| Liability for asset retirement obligation as of June 30, 2008 | | $ | 1,523,370 | |
Note 5 – Minority Interest
In connection with the Williston Basin acquisition, we entered into equity participation agreements with the lenders pursuant to which we agreed to pay to the lenders an aggregate of 12.5% of all distributions paid to the owners of PRC Williston, which at this time is 100% owned by Petro Resources. The equity participation agreements were valued at $3,401,655 and accounted for as a minority interest in PRC Williston.
| | | Minority Interest | |
| Minority interest at December 31, 2007 | | $ | 3,025,375 | |
| Earnings (loss) to minority interest | | | (349,990) | |
| Minority interest at June 30, 2008 | | $ | 2,675,385 | |
PETRO RESOURCES CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
Note 6 — Series A Preferred Stock Dividend
During the six months ended June 30, 2008, we issued 152,934 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.
Note 7 —Share Based Compensation
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 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 June 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 $80,575 of expense was recognized as of March 31, 2008. The remaining $140,250 will be recognized over the remaining service term.
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 $67,188 of expense was recognized as of March 31, 2008. The remaining $147,813 will be recognized over the remaining service term.
Petro Resources recognized stock compensation expense of $891,317 and $634,736 for the six months ended June 30, 2008 and 2007 respectively.
PETRO RESOURCES CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
A summary of option activity for the six months ended June 30, 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 | - | | | | - | |
| Outstanding at June 30, 2008 | 1,435,000 | | | $ | 3.30 | |
| | | | | | | |
| Exercisable at December 31, 2007 | 550,000 | | | $ | 3.74 | |
| Exercisable at June 30, 2008 | 902,500 | | | $ | 3.56 | |
A summary of Petro Resources non-vested options as of June 30, 2008 is presented below.
| Non-vested Options | | Shares | |
| Non-vested at December 31, 2007 | | | 575,000 | |
| Granted | | | 310,000 | |
| Vested | | | (352,500 | ) |
| Forfeited | | | - | |
| Non-vested at June 30, 2008 | | | 532,500 | |
Total unrecognized compensation cost related to non-vested options granted under the Plan was $1,115,880 and $1,853,678 as of June 30, 2008 and 2007 respectively. The cost at June 30, 2008 is expected to be recognized over a weighted-average period of 1.4 years. The aggregate intrinsic value for options was $214,700; and the weighted average remaining contract life was 3.19 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 six months ended June 30, 2008 and 2007 are disclosed in the following table:
| | | Six Months Ended June 30, | |
| | | 2008 (1) | | 2007 | |
Weighted average value per option granted during the period (2) | | $ | 1.36 | | | $ | 1.89 | |
Assumptions (3): | | | | | | | | |
| Stock price volatility | | | 104-105 | % | | | 108 | % |
| Risk free rate of return | | | 1.87-2.69 | % | | | 5.00 | % |
| | | | | | | | | |
| Expected term | | 3.5 years | | | 5.0 years | |
| (1) | Our estimated future forfeiture rate is zero. |
| (2) | Calculated using the Black-Scholes fair value based method. |
| (3) | We do not pay dividends on our common stock. | |
PETRO RESOURCES CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
A summary of warrant activity for the six months ended June 30, 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 June 30, 2008 | 6,838,962 | | | $ | 2.15 | |
| | | | | | | |
| Exercisable at December 31, 2007 | 6,838,962 | | | $ | 2.15 | |
| Exercisable at June 30, 2008 | 6,838,962 | | | $ | 2.15 | |
The aggregate intrinsic value for warrants was $3,306,371; and the weighted average remaining contract life was 2.42 years.
Note 8 – Note Payable
We amended our credit facility agreement with our lenders to modify the definition of earnings before interest, taxes, depreciation and amortization (EBITDA) and the method of calculating interest expense for our loan covenants. Due to these modifications, we met our financial covenants for the quarter ended June 30, 2008.
Note 9 – Subsequent Events
On July 17, 2008, we made an additional contribution to the Hall Houston Partnership of $1,466,520.
| ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Industry terms used in this report are defined in the Glossary of Oil and Natural Gas Terms located at the end of this Item
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 our officers or other 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.
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, are included in our filings with the SEC, including the risk factors set forth of our annual report on Form 10-K for our 2007 fiscal year and our quarterly report for the quarter ended March 31, 2008 filed with the SEC on March 31, 2008 and May 15, 2008, respectively.
General
Petro Resources Corporation and subsidiaries (“we,” “our” or “the Company”) is an independent exploration and production company engaged in acquisitions of exploratory leases, acquisitions of producing properties, secondary enhanced oil recovery projects, exploratory drilling, and production of oil and natural gas in the United States.
Our business strategy is designed to create and maximize shareholder value by combining and leveraging the knowledge and expertise of our management team with that of our industry partners to grow our diversified portfolio of oil and natural gas producing projects and prospects. Since our inception in 2005, we have established a balanced portfolio which includes producing properties, secondary enhanced oil recovery projects, and exploration prospects both onshore and offshore. We believe our current portfolio has provided a solid base of production with multiple opportunities for organic growth in both production and reserves for years into the future. We target low-to-medium risk projects that are expected to provide meaningful reserve, production and cash flow growth. We have focused our acquisition and exploration pursuits on oil and natural gas properties principally located in North Dakota, Texas, offshore Gulf of Mexico, Louisiana, and New Mexico.
In July 2005, we acquired our initial interest in drilling prospects and commenced drilling activities in November 2005. In the first quarter of 2007, we acquired oil and gas producing assets in the Williston Basin area of North Dakota. As of June 30, 2008, we held interests in approximately 185 producing wells in Texas, Louisiana and North Dakota. We also have exploratory drilling prospects located in Texas, North Dakota, Louisiana, New Mexico, Kentucky, and the Gulf of Mexico. 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. During 2007, we produced more than 120,000 boe and exited the year with a daily production exit rate of approximately 400 boe per day. During the first six months of 2008 we have produced more than 90,833 boe and our daily production exit rate was approximately 550 boe per day.
As of December 31, 2007, our estimated net total proved reserves had grown to approximately 2,716,602 boe (net of production) of which approximately 2,369,600 boe were crude oil reserves and 347,002 boe were natural gas reserves. The increase in net total proved reserves is a result of our Williston Basin acquisition that closed on February 16, 2007, positive results from enhanced oil recovery operations in North Dakota, successful exploratory drilling success in the Williston Basin and in our Cinco Terry Field in Crockett County, Texas. Our estimated reserves exclude additional reserves attributable to our 5.3% limited partnership interest in Hall-Houston Exploration II, L.P.
Our executive offices are located at 777 Post Oak Blvd., Suite 910, Houston, TX 77056, and our telephone number is (832) 369-6986. Our web site is www.petroresourcescorp.com. Additional information which may be obtained through our web site does not constitute part of this quarterly report on Form 10-Q. A copy of this quarterly report on Form 10-Q is located at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the SEC’s Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings at www.sec.gov.
Results of Operations
For the three months ended June 30, 2008 compared to the three months ended June 30, 2007
The Company’s net production for the quarter ended June 30, 2008 included 30,670 barrels of oil, 75,637 mcf of natural gas, and 5,522 barrels of natural gas liquids for a barrel-equivalent total of 48,798 boe compared to 25,282 barrels of oil, 47,027 mcf of natural gas, and 250 barrels of natural gas liquids for a barrel-equivalent total of 33,370 boe for the quarter ended June 30, 2007.
For the quarter ended June 30, 2008, the average daily production was approximately 536 boe per day and the daily exit production rate was 546 boe per day compared to average daily production of 367 boe per day and a daily exit production rate of 363 boe per day for the quarter ended June 30, 2007.
The Company realized prices for the quarter ended June 30, 2008 were $113.58 per barrel of oil, $7.91 per mcf of natural gas, and $51.95 per barrel of natural gas liquids compared to $57.86 per barrel of oil, $3.22 per mcf of natural gas, and $40.47 per barrel of natural gas liquids for the comparable prior year period.
Revenue for the quarter ended June 30, 2008 consisted $4,368,442 of oil and gas sales compared to oil and gas sales of $1,624,409 for the quarter ended June 30, 2007. The increase in revenue from oil and gas sales was due primarily to our successful secondary enhanced oil recovery operations in North Dakota and our drilling results in Crockett County, Texas as well as an increase in oil and gas prices.
Lease operating expenses for the quarter ended June 30, 2008 totaled $1,346,708 compared to lease operating expenses of $980,132 for the prior year comparable period. The increase in lease operating expenses was due primarily to increased operational costs in the Williston Basin properties and to the increase in the number of producing wells in our Cinco Terry Field in Crockett County, Texas.
Exploration costs for the quarter ended June 30, 2008 were $37,654 compared to $0 for the quarter ended June 30, 2007. Exploration costs represent our drilling costs associated with dry holes and the carrying costs of properties. The increase in exploration costs is the result of geological, geophysical, and seismic costs incurred in North Dakota and Crockett County, Texas.
We incurred no expenses related to the impairment of oil and gas properties in the quarters ended June 30, 2008 or 2007. 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. No wells needed to be written down in either quarter.
Our expenses for depreciation, depletion, and accretion for the quarter ended June 30, 2008 totaled $612,021 compared to $176,757 for the same period in the prior year. This was due to our increased production as a result of our acquisition of the Williston Basin properties and the Cinco Terry Field drilling program as well as increased depletion rates.
General and administrative expenses for the quarter ended June 30, 2008 totaled $894,329 compared to general and administrative expenses of $819,823 for the prior year period. General and administrative expenses for the quarters ended June 30, 2008 and June 30, 2007 included expenses of $296,682 and $348,311, respectively, for outstanding common stock shares and common stock options granted under our Stock Incentive Plan. Without giving effect to expenses for common shares and stock options, our general and administrative expenses for the quarters ended June 30, 2008 and June 30, 2007 were $597,647 and 471,512, respectively. The increase in general and administrative expenses (other than expenses for options and common shares) between reporting periods was due to the increase in the number of employees and their related expenses.
We incurred income from operations of $1,477,730 for the quarter ended June 30, 2008 compared to a loss from operations of $352,303 during the same period in the prior year. The increase in net income occurred due to increased revenue offset by higher lease operating expense, depletion and general and administrative costs.
During the quarter ended June 30, 2008, interest expense totaled $590,819, compared to $183,152 for the quarter ended June 30, 2007. The increase in interest expense was principally due to decreased capitalization of interest.
Beginning in March 2007, we entered into commodity derivative financial instruments for purposes of hedging our exposure to market fluctuations of oil prices. During the quarter ended June 30, 2008, we incurred a loss on derivative contracts of $2,778,056 compared to a loss of $1,277,737 for the comparable period in 2007. Our loss on derivative contracts include both $734,769 in losses on the actual settlement of certain derivative financial instruments during quarter ended June 30, 2008 and the unrealized loss of $2,043,287 based on the changes in the fair value of derivative instruments covering positions beyond June 30, 2008.
During the quarter ended June 30, 2008, we paid dividends on our Series A Preferred Stock in the amount of $277,993 compared to $162,435 during the comparable period in 2007. The dividend payments are a non-cash expense since we elected to pay the dividends in the form of additional shares of our Series A Preferred Stock.
We incurred a net loss attributable to common shareholders of $1,882,826 ($.05 per share) during the quarter ended June 30, 2008, compared to a net loss of $1,945,326 ($.09 per share) for the same period in 2007. The decrease in net loss was primarily the result of an increase in our loss on derivative contracts, interest expense and dividends, offset by an increase in our net income from operations of $1,477,730.
For the six months ended June 30, 2008 compared to the six months ended June 30, 2007
The Company’s net production for the six months ended June 30, 2008 included 60,857 barrels of oil, 122,523 mcf of natural gas, and 9,557 barrels of natural gas liquids for a barrel-equivalent total of 90,834 boe compared to 37,268 barrels of oil, 71,714 mcf of natural gas, and 653 barrels of natural gas liquids for a barrel-equivalent total of 49,874 boe for the six months ended June 30, 2007.
For the six months ended June 30, 2008, the average daily production was approximately 499 boe per day and the daily exit production rate was 546 boe per day compared to average daily production of 276 boe per day and a daily exit production rate of 367 boe per day for the six months ended June 30, 2007.
The Company realized prices for the six months ended June 30, 2008 were $99.87 per barrel of oil, $7.09 per mcf of natural gas, and $50.31 per barrel of natural gas liquids compared to $56.04 per barrel of oil, $3.68 per mcf of natural gas, and $33.16 per barrel of natural gas liquids for the comparable prior year period.
Revenues for the six months ended June 30, 2008 totaled $7,526,443 compared to revenues of $2,474,437 for the six months ended June 30, 2007. Revenue for the six months ended June 30, 2008 consisted $7,426,443 of oil and gas sales compared to oil and gas sales of $2,374,437 for the six months ended June 30, 2007. The increase in revenue from oil and gas sales was due primarily to our successful secondary enhanced oil recovery operations in North Dakota and our drilling results in Crockett County, Texas as well as an increase in oil and gas prices.
Lease operating expenses for the six months ended June 30, 2008 totaled $2,569,106 compared to lease operating expenses of $1,462,271for the prior year comparable period. The increase in lease operating expenses was due primarily to increased operational costs in the Williston Basin properties and to the increase in the number of producing wells in our Cinco Terry Field in Crockett County, Texas.
Exploration costs for the six months ended June 30, 2008 were $610,164 compared to $173,589 for the six months ended June 30, 2007. Exploration costs represent our drilling costs associated with dry holes and the carrying costs of properties. The increase in exploration costs is the result of the purchase of seismic and the write off of an exploratory well in North Dakota.
We incurred no expenses related to the impairment of oil and gas properties in the six months ended June 30, 2008, compared to $15,712 during the prior year comparable period. Impairment expenses represent the write-down of previously capitalized expenses for productive wells. We take an impairment charge for a productive well when there is an indication that we may not receive production payments equal to the net capitalized costs. The decline in expenses for impairment of oil and gas properties is the result of no wells needing to be written down to net cost.
Our expenses for depreciation, depletion, and accretion for the six months ended June 30, 2008 totaled $1,137,193, compared to $310,383 for the same period in the prior year. This was due to our increased production as a result of our acquisition of the Williston Basin properties and the Cinco Terry Field drilling program as well as an increase in depletion rates.
General and administrative expenses for the six months ended June 30, 2008 totaled $2,187,772 compared to general and administrative expenses of $1,419,314 for the prior year period. General and administrative expenses for the six months ended June 30, 2008 and June 30, 2007 included expenses of $891,317 and $634,736, respectively, for outstanding common stock shares and common stock options granted under our Stock Incentive Plan. Without giving effect to expenses for common shares and stock options, our general and administrative expenses for the six months ended June 30, 2008 and June 30, 2007 were $1,296,455 and $784,578, respectively. The increase in general and administrative expenses (other than expenses for options and common shares) between reporting periods was due to increased number of employees, additional office space, professional fees, travel and other related expenses.
We incurred income from operations of $1,022,208 for the six months ended June 30, 2008 compared to a loss from operations of $906,832 during the same period in the prior year. The increase in income is due to increased revenue offset by higher lease operating expense, depletion and general and administrative costs.
During the six months ended June 30, 2008, interest expense totaled $1,105,780, compared to $296,408 for the six months ended June 30, 2007. The increase in interest expense was principally due to decreased capitalization of interest as well as the fact that our credit facility was in place six months during 2008 and only four and one-half months during 2007.
Beginning in March 2007, we entered into commodity derivative financial instruments for purposes of hedging our exposure to market fluctuations of oil prices. During the six months ended June 30, 2008, we incurred a loss on derivative contracts of $3,463,650 compared to a loss of 726,701 for the comparable period in 2007. Our loss on derivative contracts include both $1,212,254 in losses on the actual settlement of certain derivative financial instruments during six months ended June 30, 2008 and the unrealized losses related to unsettled swap contracts of $2,147,820 and $103,576 of losses related to the floor. Unrealized losses are based on the changes in the fair value of derivative instruments covering positions beyond June 30, 2008.
During the six months ended June 30, 2008, we paid dividends on our Series A Preferred Stock in the amount of $458,801 compared to $162,435 during the comparable period in 2007. The dividend payments are a non-cash expense since we elected to pay the dividends in the form of additional shares of our Series A Preferred Stock.
We incurred a net loss attributable to common stockholders of $3,517,031 ($.10 per share) during the six months ended June 30, 2008, compared to a net loss of $2,018,037 ($.09 per share) for the same period in 2007. The increase in net loss was primarily the result of an increase in our loss on derivative contracts, interest expense and dividends, offset by an increase in our income from operations of $1,022,208.
During the six months ended June 30, 2008, cash flow provided by operations totaled $772,850 which represents an increase of $957,200 from the same period in 2007. This increase was primarily due to increased revenue offset by higher lease operating and general and administrative expense.
Plan of Operations
Our plan of operations for the next 12 months is to pursue further exploration and development of the oil and natural gas prospects that we currently own, along with obtaining the working capital required to fund such exploration and development and the acquisition of additional domestic oil and natural gas interests. We intend to pursue prospects in partnership with other companies with exploration, development and production expertise.
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.
We will seek additional working capital through bank lines of credit and project financing or through the sale of our securities. As explained under “Financial Condition and Liquidity” below, under the terms of our guarantee of a $75 million credit facility entered into by our subsidiary, PRC Williston LLC, we are prohibited from incurring any additional debt from third parties. Our ability to obtain additional working capital through third party bank lines of credit and project financing may be subject to the repayment of the $75 million credit facility.
However, as described further below, based on our present working capital, available borrowings under the credit facility and current rate of cash flow from operations, we believe we have available to us sufficient working capital to fund our operations and expected commitments for exploration and development through, at least, December 31, 2008. In the event we receive calls for capital greater than, or generate cash flow from operations less than, we expect, we may require additional working capital to fund our operations and expected commitments for exploration and development prior to December 31, 2008.
We intend to use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, financial audit, environmental, and investor relations. We believe that by limiting our management and employee costs, we may be able to better control total costs and retain flexibility in terms of project management. Consequently, we do not expect any significant change in the number of our employees, during the next twelve months.
Financial Condition and Liquidity
We estimate our revised capital budget for fiscal 2008 to be approximately $21.9 million, including:
| | · | Up to $10.0 million of capital for secondary enhanced oil recovery operations and exploratory drilling in the Williston Basin. As of June 30, 2008, we have funded approximately 2.7 million of this capital. |
| | · | Up to $4.1 million to be called upon to fund our commitment to Hall-Houston Exploration II, L. P. As of this date, we have funded approximately $5.9 million of our $8.0 million commitment and have assumed that $2.1 million of our remaining commitment will be called for during the next six months. |
| | · | Up to $7.8 million to be deployed in connection with our interest in prospects operated by Approach Resources, Inc. including our highly successful Cinco Terry field. As of June 30, 2008, we have funded approximately 3.6 million of this capital. |
As of June 30, 2008, we had total assets of $69.0 million and working capital of $9.9 million. In addition, we have available to us a $75.0 million credit facility, of which $15.6 million is outstanding as of June 30, 2008, for purposes of financing our commitments towards the drilling and development of our most significant prospect, the Williston Basin properties. Based on our present working capital, available borrowings under the credit facility and current rate of cash flow from operations, we believe we have available to us sufficient working capital to fund our operations and expected commitments for exploration and development through, at least, December 31, 2008. However, in the event we receive calls for capital greater than, or generate cash flow from operations less than, we expect, we may require additional working capital to fund our operations and expected commitments for exploration and development prior to December 31, 2008.
We will seek to obtain additional working capital through the sale of our securities and, subject to the successful deployment of our cash on hand, we will endeavor to obtain additional capital through bank lines of credit and project financing. However, other than our existing $75 million credit facility, we have no agreements or understandings with any third parties at this time for our receipt of additional working capital and we have no history of generating significant cash from oil and gas operations. Under the terms of our guarantee of the $75 million credit facility, we are prohibited from incurring any additional debt from third parties without the consent of the lenders. Our ability to obtain additional working capital through bank lines of credit and project financing may be subject to the repayment of the $75 million credit facility. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price will be materially adversely affected.
In addition, we are required to redeem our outstanding Series A Preferred Stock at a redemption price equal to the aggregate stated value of $3.00 per share plus any accrued and unpaid dividends, no later than October 2, 2008. As of this date, there are 2,563,712 shares of Series A Preferred Stock outstanding. Unless we are able to refinance the Series A Preferred Stock using our equity or a sale of some of our assets, we will need to raise additional capital in order to effect a cash redemption of the preferred shares.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet financing arrangements.
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. Barrel, 42 U.S. gallons of liquid volume, used 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.
Btu. British thermal unit, a measurement of energy equivalent to the heat needed to raise one pound of water one degree Fahrenheit.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Drilling locations. Total gross locations specifically quantified by management to be included in the Company’s multi-year drilling activities on existing acreage. The Company’s actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
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 rock named after its geographical location and dominant rock type.
Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.
Leasehold. Mineral rights leased in a certain area to form a project area.
mbbls. Thousand barrels of crude oil or other liquid hydrocarbons.
mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids
mcf. Thousand cubic feet of natural gas.
mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
mmbbls. Million barrels of crude oil or other liquid hydrocarbons.
mmboe. Million barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
mmbtu. Million British Thermal Units.
mmcf. Million cubic feet of natural gas.
Net acres, net wells, or net reserves. The sum of the fractional working interest owned in gross acres, gross wells, or gross reserves, as the case may be.
Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty of the 8/8. 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.
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 oil or 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.
Royalty interest. A share of production or the value or proceeds of production, free of the costs of production, when and if there is production. A royalty interest is usually expressed as a fraction such as 1/8.
Secondary recovery. A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection, water 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.
Water re-pressurization. A method of secondary recovery in which water is injected into the reservoir formation to increase reservoir pressure 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 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable.
ITEM 4(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 quarterly 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 a company that are designed to ensure that information required to be disclosed by a company in the reports that it files 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 is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
An evaluation was performed under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2008. Based on that evaluation, our management, including our chief executive officer and chief financial officer, has concluded that our disclosure controls and procedures were effective as of June 30, 2008.
Changes in Internal Control. We made no changes to our internal control over financial reporting during the quarter ended June 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
On June 30, 2008, in lieu of the payment of cash quarterly dividends to the holders of our Series A Preferred Stock, we issued to the holders an aggregate of 92,665 shares of our Series A Preferred Stock. The shares were issued pursuant to Section 4(2) of the Securities Act of 1933, as amended.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Our annual meeting of stockholders was held on June 5, 2008. All of the persons nominated to serve on our board of directors, namely Wayne P. Hall, Allen R. McGee, Donald L. Kirkendall, J. Raleigh Bailes, Sr., Brad Bynum, Gary L. Hall, Joe L. McClaugherty and Steven A. Pfeifer, were elected to our board of directors. In addition, our shareholders ratified the appointment of Malone & Bailey, PC as our independent registered public accounting firm for the fiscal year ending December 31, 2008, with shares voted on the ratification of our independent registered public accounting firm as follows:
| Shares voted for | | | 27,443,617 | |
| Shares against | | | 3,313,800 | |
| Shares abstaining | | | 125,057 | |
ITEM 6. EXHIBITS
| Exhibit No. | Description | Method of Filing |
| 31.1 | Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 | Filed herewith |
| | | |
| 31.2 | Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 | Filed herewith |
| | | |
| 32 | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 | Filed herewith |
SIGNATURES
In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereto duly authorized.
| | | PETRO RESOURCES CORPORATION |
| | | |
| | | |
| Date: August 12, 2008 | | /s/ Wayne P. Hall |
| | | Wayne P. Hall, |
| | | Chief Executive Officer |
| | | |
| Date: August 12, 2008 | | /s/ Harry Lee Stout |
| | | Harry Lee Stout, |
| | | Chief Financial Officer |
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