Petrol Oil & Gas 10Q 2007 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2007

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

Commission File Number: 000-30009

PETROL OIL AND GAS, INC.

(Exact name of registrant as specified in its charter)

Nevada	90-0066187
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Corporate Woods, Building 51
9393 West 110^th Street, Suite 500
Overland Park, Kansas	66210
(Address of principal executive offices)	(Zip Code)

(913) 323-4925

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the last 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 whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ____

Accelerated filer ____

Non-accelerated filer 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

The number of shares of Common Stock, $0.001 par value, outstanding on May 10, 2007 was 29,090,926 shares.

PART I -- FINANCIAL INFORMATION

Item 1. Financial Statements.

Petrol Oil and Gas, Inc.

Condensed Consolidated Balance Sheets

				March 31,		December 31,
				2007		2006
Assets					(Unaudited)		Audited

Current assets:
	Cash			$	3,980,963	$	5,917,958
	Accounts receivable				723,394		624,731
	Prepaid expenses				21,049		38,085
		Total current assets			4,725,406		6,580,774

Fixed assets:
	Pipeline				5,331,028		5,331,028
	Equipment and vehicles				341,310		341,310
					5,672,338		5,672,338
	Less accumulated depreciation				574,555		471,600
		Fixed assets, net			5,097,783		5,200,738

Other assets:
	Other assets				22,068		1,932
	Oil and gas properties using full cost accounting:
		Properties not subject to amortization			1,205,714		1,210,174
		Properties subject to amortization			21,663,298		21,856,363
	Capitalized loan costs, net				549,906		662,511
	Derivative asset				-		974,752
			Total other assets		23,440,986		24,705,732

				$	33,264,175	$	36,487,244

Liabilities and Stockholders' Equity

Current liabilities:
	Accounts payable			$	193,993	$	462,188
	Accrued liabilities				496,293		430,190
	Short-term derivative liability				1,437		-
	Current portion of long term debt				13,551,743		14,193,588
			Total current liabilities		14,243,466		15,085,966

Long-term liabilities:
	Asset retirement obligation				927,967		907,797
	Long-term derivative liability				-		58,133
	Long-term debt, less current portion				13,416,805		13,169,895
			Total long-term liabilities		14,344,772		14,135,825

Commitments and contingencies

Stockholders' Equity:
	Preferred stock, $0.001 par value, 10,000,000
		shares authorized, no shares issued and outstanding			-		-
	Common stock, $0.001 par value, 100,000,000 shares
		authorized, 29,090,926 and 29,084,597 issued and outstanding
		at March 31, 2007 and December 31, 2006 respectively			29,091		29,084
	Stock bought for services not issued, 0 and 6,329 at
		March 31, 2007 and December 31, 2006			-		6
	Unamortized cost of stock, warrants & options issued for services				(1,366,401)		(1,461,747)
	Prepaid share-based compensation				(27,200)		(47,600)
	Additional paid-in capital				28,555,484		28,555,484
	Other comprehensive income (loss)				(1,437)		916,619
	Accumulated (deficit)				(22,513,600)		(20,726,393)
					4,675,937		7,265,453

				$	$33,264,175	$	36,487,244

See notes to condensed consolidated financial statements.

Petrol Oil and Gas, Inc.

Condensed Consolidated Statement of Operations

(unaudited)

			March 31,
			2007		2006


Revenue			$	1,611,408	$	1,216,025

Expenses:
	Direct costs			754,038		585,855
	Pipeline costs			265,328		154,010
	General and administrative			250,868		364,715
	Professional and consulting fees			148,014		591,794
	Salaries and wages			82,496		51,474
	Salaries and wages - Officers			157,221		148,404
	Depreciation, depletion and amortization			652,397		464,649
		Total expenses		2,310,362		2,360,901

Net operating (loss)				(698,954)		(1,144,876)

Other income (expense):
	Interest expense			(1,088,253)		(690,320)
		Total other income (expense)		(1,088,253)		(690,320)

Net (loss)			$	(1,787,207)	$	(1,835,196)


Weighted average number of
	common shares outstanding - basic and fully diluted			29,090,926		28,033,096

Net (loss) per share - basic and fully diluted			$	(0.06)	$	(0.07)

See notes to condensed consolidated financial statements.

Petrol Oil and Gas, Inc.

Condensed Consolidated Statement of Cash Flows

(unaudited)

			Three Months Ended
			March 31,
			2007		2006
Cash flows from operating activities
Net (loss)			$	(1,787,207)	$	(1,835,196)
Depreciation, depletion and amortization				539,792		480,691
Warrant accretion				293,332		260,294
Shares issued for interest				-		153,527
Accretion of asset retirement obligation				20,170		-
Warrants, options and shares issued for services				115,746		472,918
Adjustments to reconcile net (loss) to cash
	used in operating activities:
		Accounts receivable		(98,663)		(151,747)
		Prepaid and other assets		17,036		-
		Accounts payable		(268,195)		(724,987)
		Accrued liabilities		66,104		76,011
Net cash used in operating activities				(1,101,885)		(1,268,489)

Cash flows from investing activities
	Additions to other assets			(20,136)		-
	Purchase of other property and equipment			-		(37,089)
	Additions to oil and gas properties not subject to amortization			-		(67,173)
	Additions to oil and gas properties subject to amortization			(239,313)		(4,257,159)
	Purchase of pipeline assets			-		(1,624,662)
Net cash used in investing activities				(259,449)		(5,986,083)

Cash flows from financing activities
	Amortized loan fees			112,605		-
	Payments on notes payable			(688,266)		(8,864)
	Proceeds from the exercise of warrants			-		150,000
Net cash provided from (used in) financing activities				(575,661)		141,136

Net decrease in cash				(1,936,995)		(7,113,436)
Cash - beginning				5,917,958		8,435,203
Cash - ending			$	3,980,963	$	1,321,767

Supplemental disclosures:
	Interest paid		$	825,909	$	415,777
	Income taxes paid			-		-

Non-cash transactions
	Shares issued for oil and gas properties		$	-	$	60,500
	Shares issued for debt conversion		$	-	$	685,146

See notes to condensed consolidated financial statements.

Petrol Oil and Gas, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1 - Basis of Presentation

The unaudited condensed consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and reflect all adjustments which, in the opinion of management, are necessary for a fair presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim period are not necessarily indicative of the results to be expected for a full year. Certain amounts in the prior year statements have been reclassified to conform to the current year presentations. These statements should be read in conjunction with the financial statements and footnotes thereto included in the Form 10-K for the year ended December 31, 2006.

Note 2 - Going Concern

The accompanying condensed consolidated financial statements have been prepared assuming that we will continue as a going concern. Our ability to continue as a going concern is dependent upon attaining profitable operations based on the development of products that can be sold. We intend to use borrowings and security sales to mitigate the affects of our cash position, however, no assurance can be given that debt or equity financing, if and when required, will be available. The financial statements do not include any adjustments relating to the recoverability and classification of recorded assets and classification of liabilities that might be necessary should we be unable to continue in existence.

Note 3 - Stock Transactions and Consulting Agreements

During the three months ended March 31, 2007, we issued 6,329 shares of our common stock as previously authorized for public relations services.

A summary of stock options and warrants is as follows:

	Options		Warrants
Outstanding 01/01/07	2,810,000	$1.70	14,936,666	$1.93
Granted	-	-	-	-
Cancelled	(300,000)	1.42	(1,495,000)	.87
Exercised	-	-	-	-
Outstanding 3/31/07	2,510,000	$1.74	13,441,666	$2.05

See note 6 for subsequent event regarding cancellation of options in May 2007.

Note 3 - Asset Retirement Obligation

Our asset retirement obligations relate to the abandonment of oil and gas wells. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, inflation rates and credit adjusted risk-free interest rates. The following shows the changes in asset retirement obligations for the financial statements presented.

Petrol Oil and Gas, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

	March 31, 2007
Asset retirement obligation, beginning of year	$ 907,797
Liabilities incurred during the year	--
Liabilities settled during the year	--
Accretion of expense	20,170
Asset retirement obligations, end of year	$ 927,967

Note 4 - Long-Term Debt

Long-term debt consists of the following:

	March 31, 2007
Total notes payable	$ 27,781,762

Less unamortized cost of warrants	(813,214)

	26,968,548

Less current portion	(13,551,743)
Total long-term debt	$ 13,416,805

During the quarter ended March 31, 2007, the accretion of the warrants that was included in interest expense totaled $293,332.

Note 5 - Fixed Price Sales Contracts

We have entered into various contracts with our customers to sell gas and oil at a fixed price. At March 31, 2007, we had contracts covering approximately 35,000 mmbtu per month for the period of April 2007 to March 2008 at an average price of $7.32 per mmbtu.

Note 6 - Subsequent Events

On May 4, 2007, our president and chief executive officer retired. Pursuant to his retirement agreement, 1,750,000 options to purchase common stock were cancelled and we recorded a liability of $135,000 in May to reflect severance payments owed.

FORWARD-LOOKING STATEMENTS

This document contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to, any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objections of management for future operations; any statements concerning proposed new services or developments; any statements regarding future economic conditions or performance; any statements of belief; and any statements of assumptions underlying any of the foregoing.

Forward-looking statements may include the words “may,” “could,” “estimate,” “intend,” “continue,” “believe,” “expect” or “anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this report. Except for our ongoing securities laws, we do not intend, and undertake no obligation, to update any forward-looking statement.

Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-looking statements, are subject to change and inherent risks and uncertainties. The factors impacting these risks and uncertainties include, but are not limited to:

attainment of profitable operations based on the development of oil and gas products that can be sold, and the continued availability of debt or equity financing. The Company’s ability to continue to operate is contingent on refinancing or restructuring indebtedness. See “Liquidity and Capital Resources”.
increased competitive pressures from existing competitors and new entrants;
increases in interest rates or our cost of borrowing or a default under any material debt agreements;
deterioration in general or regional economic conditions;
adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations;
hedging risks;
ability to attract and retain key personnel;
inability to achieve future sales levels or other operating results;
fluctuations of oil and gas prices;
the unavailability of funds for capital expenditures; and
operational inefficiencies in distribution or other systems.

For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, please see Part II, Item 1A. Risk Factors, in this document.

In this form 10-Q references to “PETROL”, “the Company”, “we,” “us,” and “our” refer to PETROL OIL AND GAS, INC.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

OVERVIEW AND OUTLOOK

We are an oil and gas exploration, development and production company. Our properties are located in the Cherokee and Forrest Basins along the Kansas and Missouri border. Our corporate strategy is to continue building value through the development and acquisition of gas and oil assets that exhibit consistent, predictable, and long-lived production. Our current focus is Coal Bed Methane reservoirs in the central U.S., which produce both Coal Bed Methane (“CBM”) and at times conventional gas.

Results of Operations for the Three Months Ended March 31, 2007 and 2006.

The following table summarizes selected items from the statement of operations at March 31, 2007 compared to March 31, 2006.

INCOME:

	Three Months Ended March 31,
	2007	2006	Increase / (Decrease)
	Amount	Amount	$	%
Revenues	$ 1,611,408	$ 1,216,025	$ 395,383	33%

Revenues

Revenues for the three months ended March 31, 2007 were $1,611,408 compared to revenues of $1,216,025 in the three months ended March 31, 2006. This resulted in an increase of $395,383 or 33%, from the same period one year ago. The increase in revenues is primarily the result of increased production, together with improved pricing after impact of the Company’s hedging activities.

EXPENSES:

	Three Months Ended March 31,
	2007	2006	Increase / (Decrease)
	Amount	Amount	$	%
Expenses:
Direct Costs	$ 754,038	$ 585,855	$ 168,183	29%
Pipeline costs	265,328	154,010	111,318	72%
General and administrative	250,868	364,715	(113,847)	(31%)

Professional and consulting fees	148,014	591,794	(443,780)	(75%)
Salaries and wages	82,496	51,474	31,022	60%
Salaries and wages - Officers	157,221	148,404	8,817	6%
Depreciation, depletion and amortization	652,397	464,649	187,748	40%
Total expenses	2,310,362	2,360,901	(50,539)	(2%)

Net operating (loss)	(698,954)	(1,144,876)	(445,922)	(39%)

Other income (expense):
Interest expense	(1,088,253)	(690,320)	397,933	58%

Net loss	$(1,787,207)	$(1,835,196)	$ (47,989)	(3%)

Direct Costs

Direct costs are the costs associated with operating producing wells, and transporting the oil and natural gas to the market for sale. Direct costs for the three months ended March 31, 2007 were $754,038, an increase of $168,183, or 29%, from $585,855 for the three months ended March 31, 2006. The increase over the prior period is a result of additional operating and repair costs associated with the accelerated dewatering activities at the Company’s Coal Creek Project.

Pipeline Costs

Pipeline costs for the three months ended March 31, 2007 were $265,328, an increase of $111,318, or 72%, from $154,010 for the three months ended March 31, 2006. The increase in pipeline costs in the current period was a result of the Company bringing online the Burlington and Waverly pipelines in April of 2006.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2007 were $250,868, a decrease of $113,847, or 31%, from $364,715 for the three months ended March 31, 2006. The decrease in general and administrative expenses is attributable to streamlining and reduction of expenses.

Professional and Consulting Fees

Professional and consulting fees for the three months ended March 31, 2007 was $148,014, a decrease of $443,780, or 75%, from $591,794 for the three months ended March 31, 2006. The decrease in professional and consulting fees in the current period was a result of decreased investor relations fees and a lessened reliance on outside consultants..

Salaries and Wages

Salaries and wages for the three months ended March 31, 2007 was $82,496, an increase of $31,022, or 60% from $51,474 for the three months ended March 31, 2006. The increase in salaries and wages in the current period was a result of a reclassification of certain direct field labor to Salaries and Wages..

Salaries and Wages – Officer

Salaries and wages – officer, for the three months ended March 31, 2007 was $157,221 compared to $148,404 in the three months ended March 31, 2006. The increase in the amount of $8,817 or 6% is primarily due to scheduled pay increases, as provided in the employment contract of the officer.

Depreciation, Depletion, and Amortization Expense

Depreciation, depletion, and amortization expense for the three months ended March 31, 2007 was $652,397, an increase of $187,748, or 40%, from $464,649 for the three months ended March 31, 2006. The increase in depreciation, depletion and amortization expense was a result of increased depletion on each unit of production due to our increase in capital expenditures and a slight decline in reserves.

Net Operating (Loss)

The net operating loss for the three months ended March 31, 2007 was $698,954, versus a net operating loss of $1,144,876 for the three months ended March 31, 2006, a change in net loss of $445,922 or 39%. The decrease in net operating loss for the first quarter of 2007 was primarily due to our 33% increase in revenues while we had an overall slight decrease in expenses.

Other Income (Expense)

Interest expense

Interest expense for the three months ended March 31, 2007 was $1,088,253, an increase of $397,933, or 58%, from $690,320 for the three months ended March 31, 2006. The increase in interest expense is primarily the result of increased financing.

Net Loss

Our net loss for the three months ended March 31, 2007 was $1,787,207, a decrease of $47,989, or 3%, from $1,835,196 for the three months ended March 31, 2006. The decrease in net loss is primarily the result of increased revenues, offset by additional interest expense.

Contractual Obligations

Future payments due on our contractual obligations as of March 31, 2007 are as follows:

	Total	2007	2008-2009	2010-2011	Thereafter

Laurus Convertible Note	$ 2,747,207	$ 2,747,207	$ --	$ --	$ --
Laurus Term Notes	25,000,000	11,464,107	13,535,893	--	--
Asset retirement obligations	927,967	--	--	--	927,967
Notes Payable	34,559	11,000	23,559	--	--
Total	$28,709,733	$14,222,314	$13,559,452	$ --	$ --

Analysis and Discussion of Cash Flow

In the three months ended March 31, 2006 our cash position decreased by $1,936,995. Our operating activities utilized $1,101,885 of cash mainly from operating expenses we incurred.

Operation Plan

In 2007 we plan to continue to focus our efforts on increasing production, improving our asset base, and enhancing our net asset value. The ability to accomplish these objectives is dependent, to a significant degree, on our ability to generate or acquire cash sufficient to maintain operations. We expect to achieve this through the:

sustained development and production of CBM and other natural gases on our existing properties at the Petrol-Neodesha Project,
assessing the technical, economic and pace of development of our 92,000 gross acre Coal Creek Project
pursuing strategic acquisitions of producing properties; and
creating value by furthering our business plan.

Coal Creek Project

Petrol began implementing its development program on the Coal Creek Project in November 2005 with the first $10,000,000 draw down from our $50,000,000 financing arrangement with Laurus Master Funds.

The net proceeds derived from the first Laurus Master Funds Financing transaction were used in the development of two areas within the Coal Creek project, specifically the Burlington area and the Waverly area. This first round of financing allowed Petrol to emplace or complete production wells, salt water disposal wells and install miles of gas gathering pipelines, salt water disposal lines, compressor stations and gas processing systems within those production areas.

Petrol received an additional $15,000,000 from its Laurus Credit facility during the spring of 2006. A portion of these additional funds were used to finalize the completion of some of the original Phase I wells, drilled new CBM wells and add 2 new salt water disposal wells, as

well as to continue the integration of the gas gathering and water disposal system and pipelines. In addition to the drilling process Petrol undertook a comprehensive testing program to identify, quantify and rank the most productive water producing intervals.

The Coal Creek Project includes 51 production wells and 5 salt water disposal wells. Initially most of the production wells were connected to the gas gathering systems and water disposal system in order to de-water these CBM wells and promote gas production as quickly and efficiently as possible. During the second half of 2006 it became evident that water production rates from the producing coal seams in both Burlington and Waverly were higher than anticipated and thus two additional salt water disposal were drilled, one in Burlington and one in Waverly. The inclusion of these new SWD’s has almost doubled the available salt water disposal capacity in Burlington and Waverly; however, the higher water rates and time involved in bringing these SWD’s on line, has delayed our ability to assess production capacities of this project.

To further our understanding of the water and gas production mechanisms from these multiple coal seams Petrol has concentrated its technical efforts on a cluster of 5-6 closely spaced wells in Burlington and Waverly. Our objective is to de-water these wells and the area around these wells as quickly and effectively as possible thus exposing the gas bearing coal seams directly to the wellbore. The methodology being employed to attain that objective includes:

increasing the size of the downhole pumps in order to produce as much water as the well can possibly produce.
employing new chemical additives and stronger pump rods that should reduce down time and permit sustained and continuous production periods.
gathering daily detailed measurements of these wells behavior which is captured and reviewed by the technical staff on a weekly basis.

Since the Burlington area was developed first those wells in addition to having longer and sustained de-watering times also have some conventional sandstone reservoirs and therefore have been selling gas into the Enbridge Interstate pipeline since late April 2006. However the implementation of our testing and analysis efforts involving our cluster wells described above has at times interrupted or curtailed gas production and thus sales.

The Waverly wells have been in various stages of de-watering and the sustained disposal rates improved substantially following the inclusion and operation of a new SWD well in early October 2006. Gas production from the wells is modest and has not as yet reached the level or sustainability to meet Enbridge pipeline requirements.

The entire Coal Creek development plan includes drilling and completing about 540 production wells along with three gas gathering pipeline and gas processing systems. The pace of the development will obviously depend on the availability of adequate ongoing financing program, the economic and technical conclusions based on the analysis of our cluster well program and favorable market conditions.

Our future financial results will depend primarily on: (i) the ability to continue to produce gas and oil from existing wells; (ii) the ability to discover commercial quantities of natural gas and oil; (iii) the market price for oil and gas; and (iv) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources. In order to be successful in all or any of these respects, the prices of oil and gas prevailing at the time of production must be at a level allowing for profitable production, and we must be able to obtain additional funding to increase our capital resources.

Petrol-Neodesha Project

Petrol-Neodesha and our oil properties currently provide ongoing revenue and cash from sales of oil and gas. As we expand development and operational activities, we will weigh the pace of further drilling and development against the availability of internal and external funding. The technical and base economics issues in Petrol-Neodesha are clear and thus continued development involves far less risk than might be expected in new un-development areas. Given appropriate economics we plan to continue to develop this property.

With the enhancements to gas gathering pipeline systems that Petrol finalized late spring and early summer of 2005 we now have additional pipeline capacity to fully develop this 10,000 gross acre property. During 2006 we have added a total of 17 new or re-completed production wells to the 14 new production wells we drilled and completed in 2005. All 31 new production wells were 100% successful.

During the second and third quarters of 2006 we initiated a technical program designed to improve our overall understanding of the effectiveness of multi-zone stimulations and their ability to enhance production and reduce stimulation costs. Our expectations are to implement this program throughout the year employing advanced stimulation methodologies and re-completion techniques. Real time data acquisition and state-of-the-art fracture modeling were employed on several of our multi-stage fracture stimulations. The information derived during these tests provided both our field project personnel and the fracture service company with a much improved understanding of the physical processes that may be occurring about 1,500 ft below the surface. Further with real time data and modeling it allows the fracture stimulation process to be altered and improved instantly. Petrol retained Pinnacle Technologies of Houston and Pentagon Technical Services of Denver to provide technical consulting and field support on specific fracturing/chemical strategies to optimize our completion techniques, reduce operational costs and improve production at our Neodesha and Coal Creek project areas.

Liquidity and Capital Resources

The following table summarizes total assets, accumulated deficit, stockholders’ equity and working capital at March 31, 2007 compared to December 31, 2006.

	March 31, 2007	December 31, 2006	Increase / (Decrease)
	March 31, 2007	December 31, 2006	$	%

Current Assets	$4,725,406	$6,580,774	$(1,855,368)	(28%)

Current Liabilities	$14,243,466	$15,085,966	$(842,500)	(6%)

Working Capital (deficit)	$(9,518,060)	$(8,505,192)	$1,012,868	12%

Financing. On October 28, 2004, we entered into agreements with Laurus Master Fund, Ltd., a Cayman Islands corporation. Under the terms of the Laurus Funds agreements we issued a Secured Convertible Term Note (the “Note”) in the aggregate principal amount of $8,000,000 and a five-year warrant (the “Warrant”) to purchase 3,520,000 shares of our common stock at $2.00 per share and 1,813,333 shares of our common stock at $3.00 per share. On June 2, 2006, Laurus transferred the 5,333,333 warrants to Pallas Production Corp. (“Pallas”). The Note is convertible into shares of our common stock at a fixed conversion price of $1.50 per share. The Note has a three-year term and bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3%, subject to a floor of 7.5% per annum.

On January 28, 2005, we amended the Laurus Note and the Registration Rights Agreement. Laurus agreed to move five months of principal payments (January through May of 2005) to be paid on the Maturity Date (October 28, 2007). Additionally, Laurus agreed to extend certain filing and effectiveness dates under the registration rights agreement. In consideration for the amendment, we issued an additional common stock purchase warrant to Laurus to purchase up to 1,000,000 shares of our common stock at $2.50 per share for the first 666,667 shares and $3.00 per share for the remaining 333,333 shares. On June 20, 2006, Laurus transferred the 1,000,000 warrants to Pallas. Further, pursuant to the amendment agreement executed on April 28, 2004, we have agreed to file semi-annual registration statements to register shares of our common stock issued to Laurus for the conversion of interest under the Note.

As of March 31, 2007, Laurus has converted $2,283,823 of principal payments into 1,522,550 shares of our common stock and $779,352 of accrued interest into 519,568 shares of our common stock (2,042,118 shares in total). The conversion of principal and accrued interest allowed us additional cash to use in our operations.

On October 31, 2005, we entered into another financing agreement with Laurus, under which $10,000,000 was funded into an escrow account and was disbursed to us in November 2005 after finalization of certain closing requirements. We issued a three-year Secured Term Note in the aggregate principal amount of $10,000,000 and a five-year warrant to purchase 1,000,000 shares of our common stock at $2.00 per share. On June 20, 2006, Laurus transferred the 1,000,000 warrants to Pallas. The note bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3.25%, subject to a floor of 10% and a ceiling of 14% per annum. In addition, Laurus, in their sole discretion, was able to purchase

additional notes from us in an aggregate principal amount of up to $40,000,000 pursuant to substantially similar terms of the initial note dated October 31, 2005.

On March 31, 2006, we entered into agreements with Laurus to draw down an additional $5,000,000 under the credit facility provided by Laurus in October 2005. Under the terms of the Laurus agreements we issued a Secured Term Note in the aggregate principal amount of $5,000,000 and a five-year warrant to purchase 200,000 shares of our common stock at $1.80 per share. On June 20, 2006, Laurus transferred the 200,000 warrants to Pallas. The Note has a three-year term and bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3.25%, subject to a floor of 10% and a ceiling of 14% per annum. Concurrently with the agreements listed above, we amended and restated our previous $10,000,000 Secured Term Note dated October 31, 2005 with Laurus.

On April 7, 2006, the funds were released from Escrow. Net proceeds to Petrol from the financing, after payment of fees and expenses to Laurus and its affiliates, were $4,806,688. The proceeds were primarily utilized by Petrol for drilling activities on our Coal Creek Project.

On May 31, 2006, we entered into agreements with Laurus to draw down an additional $10,000,000 under the credit facility provided by Laurus in October 2005. Under the terms of the Laurus agreements we issued a Secured Term Note in the aggregate principal amount of $10,000,000 and a five-year warrant to purchase 400,000 shares of our common stock at $1.65 per share. On June 20, 2006, Laurus transferred the 400,000 warrants to Pallas.The Note has a three-year term and bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3.25%, subject to a floor of 10% and a ceiling of 14% per annum. Concurrently with the execution of the new Laurus Funds agreements, Petrol amended and restated its previous $10,000,000 Secured Term Note dated October 31, 2005 and the $5,000,000 Secured Term Note dated March 31, 2006 with Laurus Funds.

On June 2, 2006, the funds were released from Escrow. Net proceeds to Petrol from the financing, after payment of fees and expenses to Laurus Funds and its affiliates, were $9,629,679. The proceeds were primarily utilized by Petrol for drilling activities on Petrol’s Coal Creek Project.

Cash Flows. Since inception, we have financed cash flow requirements through debt financing, the issuance of common stock and revenues generated from the sale of oil and gas. As we expand operational activities, we may experience net negative cash flows from operations, pending receipt of sales or development fees, and may be required to obtain additional financing to fund operations through common stock offerings and debt borrowings to the extent necessary to provide working capital.

Satisfaction of our cash obligations for the next 12 months.

A critical component of our operating plan impacting our continued existence is to efficiently manage the production from our Petrol-Neodesha Development and successfully develop our Coal Creek Project. Our ability to obtain additional capital through additional equity and/or debt financing, and Joint Venture or Working Interest partnerships will also be important to our expansion plans. In the event we experience any significant problems assimilating

acquired assets into our operations or cannot obtain the necessary capital to pursue our strategic plan, we may have to reduce the growth of our operations. This may materially impact our ability to increase revenue and continue our growth.

We believe that our existing capital combined with cash flow from operations will only be sufficient to sustain our operations, without additional financing, through fiscal 2007.

We may incur operating losses over the next twelve months. Our lack of operating history particularly at Coal Creek makes predictions of future operating results difficult to ascertain. Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development and production, particularly companies in the oil and gas industry. Such risks include, but are not limited to, an evolving and unpredictable business model and the management of growth. To address these risks we must, among other things, implement and successfully execute our business and marketing strategy, continue to develop and upgrade technology and products, respond to competitive developments, and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.

Under our current operating plan, we are required to make certain lease payments to maintain our rights to develop and drill for oil and gas. These lease payments are material obligations to us.

Summary of product and research and development that we will perform for the term of our plan.

Field Development

Our original Operation Plan for field development included a mix of lease acquisition and the purchase of existing producing properties. It started with identifying the most promising and cost-effective drill sites on our current leased acres, drilling and testing wells to prove reserves, completing the more promising test wells, extracting the gas, oil and other hydrocarbons that we find, and delivering them to market.

In October 2004 we purchased an existing 10,000 gross acre gas producing property we called Petrol-Neodesha. Petrol-Neodesha provided us with revenue and an opportunity to enhance production in a producing area as well as gain important hands on experience and insight into the field wide development slated for Coal Creek.

In 2005 we believed that we had leased sufficient mineral acreage in and around Coffey County, KS to move forward with field development of the area and with the proceeds of financing with Laurus Master Funds we proceeded with the development of our Coal Creek Project. That development accelerated in early 2006 and continues throughout the year.

Coal Creek

Our plan called for an exploration and development phase involving the drilling and testing of 18 exploratory wells in the Coal Creek project. Data and analysis acquired from these initial test wells provided our geologists and engineers with information that supported the quantitative determination concerning the gas content, reserve estimates and potential to produce commercial rates of CBM and other types of more conventional natural gas. By design most of these wells were located in proximity to an existing interstate gas pipeline. The total drilling depth of exploratory wells in Coal Creek was approximately 1,700 ft.

Kansas Geologic Society (KGS) joined us in our field operations to help in assessing the gas reserves from our CBM exploratory/test wells in the Coal Creek Project. KGS took samples from multiple coal beds found at various depths in these test wells. They performed laboratory type analysis to acquire gas content in the coals. Their laboratory results yielded values similar to those obtained by our geologist, Mr. William Stoeckinger, from sampling of some of our other exploratory/test wells. We view these independent gas content values quite favorably since they indicate quantitative similarities to the CBM producing coal beds found in our Petrol-Neodesha Project just south of the Coal Creek Project.

Based on our first series of exploratory/test wells and current bid pricing we anticipate that each well in our Coal Creek Project will cost approximately $180,000, which includes locating, drilling, testing, hydraulically fracturing and connecting to the gas gathering pipeline. Operational costs are expected to be about $1,150 per month per well to pay for electricity, pulling and repairs, pumping, general maintenance and other miscellaneous charges. In support of these operations we have working agreements with local third parties to monitor and maintain our wells and perform drilling and work-over activities

Our Independent Reserve Report dated December 31, 2005 indicated we had significant proven undeveloped gas reserves on our leases in the Coal Creek Project to warrant development and thus in November 2005 with these and the other technical data described above we began the development of the Coal Creek Project with the intent of producing those reserves, increasing revenues and enhancing the Net Asset Value of that Project area.

Coal Creek has 51 production wells and 5 SWD wells with 32 of those production wells and 3 SWD wells located in the Burlington area and 19 of those production wells and 2 SWD well located in the Waverly area. Each area has its own gas gathering pipelines, water disposal lines, compressors and gas processing equipment to make connections with the Enbridge interstate pipeline.

Early water production from these Coal Creek producing intervals was found to be considerably higher than those found in the more mature production intervals of our Neodesha wells. Further, as many as 10-12 coal beds and shales were completed in the Coal Creek project wells compared to 2-3 coal beds normally completed in the Neodesha wells thus compounding the comparison between the two areas. To further our understanding of the water and gas production mechanisms from these multiple coal seams in Coal Creek Petrol has concentrated its

technical efforts on some closely spaced cluster wells. Our objective is to de-water these wells and the area around these wells as quickly and efficiently as possible thus exposing the gas bearing coal seams directly to the wellbore and acquire as much technical data as possible.

Some of the Coal Creek wells that were developed first in addition to having longer and sustained de-watering times also have some conventional sandstone reservoirs and therefore have been selling gas into the Enbridge Interstate pipeline. However the implementation of our testing and analysis efforts involving our cluster wells described above has at times interrupted or curtailed gas production and thus sales.

Petrol plans to continue the assessment and development of its Coal Creek Project with the pace and timing of the development depending on the availability of financing, the economic and technical conclusions based on the analysis of our cluster well program and favorable market conditions.

Petrol-Neodesha

Our Petrol-Neodesha project has room for another 50 to 100 wells to be drilled or re-completed in new reservoirs in order to fully develop this existing 10,000 gross leased mineral acreage. In 2005, we finalized enhancing the production capacity of our gas gathering system which included the addition of several new booster pumps and miles of larger diameter trunk lines that will accommodate production for all our new or re-completed wells. During 2006, Petrol drilled or re-completed 17 production wells on the Petrol-Neodesha properties, with a 100% success rate. All these new wells have been connected to our gas gathering pipeline system.

We plan to continue implementing our Neodesha development that includes implementing technical programs employing advanced stimulation methodologies and re-completion techniques. These technical programs are designed to improve our overall understanding of the effectiveness of multi-zone stimulations and their ability to enhance production and reduce stimulation costs.

With cumulative gas production for 2006 from Petrol-Neodesha reaching a new high of about 0.998 Bcf we expect to continue seeking acquisition opportunities which compliment this current production area and expand the field wide development of Petrol-Neodesha.

General Operations

Petrol’s field development plans and strategies are employed throughout its multiple project areas and incorporates several assessment stages. Each new well is drilled through all possible CBM reservoirs and individually evaluated. Upon a favorable evaluation of its overall production capacity the well will be fully completed in as many gas producing intervals as possible and then connected to our local gas gathering and water disposal pipelines.

When a proposed drilling site is identified, as a licensed operator in the State of Kansas and Missouri, Petrol is engaged in all aspects of well site operations. As a state licensed operator

we are responsible for permitting the well, which includes obtaining permission from the Kansas Oil and Gas Commission or Missouri relative to spacing requirements and any other county, state and federal environmental regulatory issues required at the time that the permitting process commences. Additionally, Petrol formulates and delivers to all interest owners an operating agreement establishing each participant’s rights and obligations in that particular well based on the location of the well and the ownership. In addition to the permitting process, we as the operator are responsible for hiring the driller, geologist and land men to make final decisions relative to the zones to be targeted, confirming that we have good title to each leased parcel covered by the spacing permit and to actually drill the well to the target zones. Petrol is responsible for completing each successful well and connecting it to the most appropriate section of the gas gathering system.

As the operator we are also the caretaker of the well once production has commenced. We are responsible for paying bills related to the drilling and development of the well, billing working interest owners for their proportionate expenses in drilling and completing the well, and selling the production from the well. Once the production is sold, we anticipate that the purchaser thereof carries out its own research with respect to ownership of that production and sends out a division order to confirm the nature and amount of each interest owned by each interest owner. Once a division order has been established and confirmed by the interest owners, the production purchaser issues the checks to each interest owner in accordance with its appropriate interest. From that point forward, we as operator are responsible for maintaining the well and the well site during the entire term of the production or until such time as we have been replaced or the site appropriately abandoned.

Along with the drilling and completion of our production wells our subsidiary pipeline companies formulate, design and install a gas gathering and compression system to transport the gas from wellhead to the high pressure interstate pipeline tap and sales market. Our experience in Petrol-Neodesha is being brought to bear on our new development area in Coal Creek. We have identified several major interstate distribution pipelines that operate within and pass through the counties in which we have lease holdings. These include pipelines owned and operated by Southern Star, CMS Energy, Enbridge and Kinder Morgan. We have initiated contact with these companies to ascertain the specific locations of their pipelines, their requirements to transport gas from us (including volume of gas and quality of gas), and the costs to connect to their pipelines. We currently have agreements with Southern Star in our Petrol-Neodesha Project and Enbridge in our Coal Creek Project

Petrol continues to assess the costs of transporting our gas products from the producing wells to the nearest appropriate interstate pipeline. The cost of installing a distribution infrastructure or local gathering system varies depending upon the distance the gas must travel from wellhead to the compressor station and high pressure pipeline tap, and whether the gas must be treated to meet the purchasing company’s quality standards. However, based on the close proximity of several major distribution pipelines to our leased properties, plus our intent to drill as close to these pipelines as practicable, at present we estimate the total cost of installing a distribution infrastructure for a group of about 50-75 producing wells to be approximately $6,500-7,500 each plus a one-time expense of $5,000 per well to tap into the high pressure interstate pipeline and support a compressor and monitoring system.

The price obtained for produced oil and gas is dependent on numerous factors beyond our control, including domestic and foreign production rates of oil and gas, market demand and the effect of governmental regulations and incentives. To reduce the impact of these extraneous factors we often enter into forward sales contracts for a portion of the gas and oil we produce. However, we do not have any delivery commitments for gas or oil from wells not currently drilled or producing. Because the U.S. government’s has been encouraging increases in domestic production of energy, coupled with the high demand for natural gas, we do not anticipate any difficulties in selling any oil and gas we produce, once it has been delivered to a distribution facility.

The timing of most of our capital expenditures is discretionary. Currently there are no material long-term commitments associated with any capital expenditure plans or that are currently in the investigative planning stage. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. The level of our capital expenditures will vary in future periods depending on energy market conditions and other related economic factors.

Significant changes in the number of employees

We currently have four full time employees and two part time employees as well as twelve contract personnel that support and operate our field operations. We do not anticipate a significant change in the number of full time employees over the next twelve months. We intend to use the services of independent consultants and contractors to perform various professional services, particularly in the area of land services, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain general and administrative expenses.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results or operations, liquidity, capital expenditures or capital resources that is material to investors.

Derivatives

To reduce our exposure to unfavorable changes in natural gas prices we have entered into an agreement to utilize energy swaps in order to have a fixed-price contract. This contract allows us to be able to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided under the contracts. However, we will not benefit from market prices that are higher than the fixed prices in our contracts for hedged production. If we are unable to provide the quantity that we have contracted for we will have to go to the open market to purchase the required amounts that we have contracted to provide.

The following table summarizes our fixed price contracts as of December 31, 2006:

	Year Ending December 31,
	2007	2008
Gas
Contract volume	460,500	91,500
Weighted-average price	$7.95	$7.32

Oil Contract volume	--	--
Weighted-average price	--	--

Fair value asset (liability)	$974,752	($58,133)

On October 9, 2006, we entered into a “Fixed Price Contract” to sell 1,000.0 DTH per day of our natural gas productions at a fixed price of $7.32 per DTH. The contract period begins April 1, 2007 and expires on March 31, 2008.

Critical Accounting Policies and Estimates

Our accounting estimates include bad debts on our receivables, amount of depletion of our oil and gas properties subject to amortization, the asset retirement obligation and the value of the options and warrants that we issue. Our trade receivables have been fully collectible since inception and we only have sales to a small base of customers. We believe that all of our receivables are collectible. The depletion of our oil and gas properties is based in part on the evaluation of our reserves and an estimate of our reserves. We obtain an evaluation of the proved reserves from a professional engineering company and on a quarterly basis we review the estimates and determine if any adjustments are needed. If the actual reserves are less than the estimated reserves we would not fully deplete our costs. The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for Petrol. If costs rise more than what we have expected there could be additional charges in the future however we monitor the costs of the abandoned wells and we will adjust this liability if necessary. The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants we determine the volatility of our stock. We believe our estimate of volatility is reasonable and we review the assumptions used to determine this whenever we have an equity instrument that needs a fair market value. Although the offset to the valuation is in paid in capital were we to have an incorrect material volatility assumption our expenses could be understated or overstated. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in

circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors.

Effects of Inflation and Pricing

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Material changes in prices impact revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate the increased business costs will continue while the commodity prices for oil and natural gas, and the demand for services related to production and exploration, both remain high (from a historical context) in the near term.

Item 3. Quantitative and Qualitative Disclosure About Market Risk.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue. Monthly oil price realizations ranged from a low of approximately $40.73 per barrel to a high of approximately $64.00 per barrel during 2005 and as high as $76.00 per barrel during the nine months ended September 30, 2006. Gas price realizations ranged from a monthly low of approximately $5.02 per Mcf to a monthly high of approximately $9.10 per Mcf during the same period.

Depending on the level of new well development, management expects revenue to grow in the foreseeable future. In order to reduce natural gas price volatility, we have entered into hedging transactions.

Normal hedging arrangements have the effect of locking in for specified periods the prices we would receive for the volumes and commodity to which the hedge relates. Consequently, while hedges are designed to decrease exposure to price decreases, they also have the effect of limiting the benefit of price increases.

Interest Rate Risk

Our long term debt with Laurus Funds has a floating interest rate of prime plus 3% to 3.25%, with a floor of 7.5% to 14%. Therefore, interest rate changes will impact future results of operations and cash flows.

Item 4. Controls and Procedures.

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports filed under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the specified time periods. As of the end of the period covered by this report, Paul Branagan, our former Chief Executive Officer and Principal Financial Officer evaluated the effectiveness of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based on the evaluation, which disclosed no significant deficiencies or material weaknesses, Mr. Branagan, our former Chief Executive Officer and Principal Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting him to material information required to be included in our periodic SEC filings.

It should be noted, however, that no matter how well designed and operated, a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events. Because of these and other inherent limitations of control systems (including faulty judgments in decision making or breakdowns resulting from simple errors or mistakes), there can be no assurance that any design will succeed in achieving its stated goals under all potential conditions. Additionally, controls can be circumvented by individual acts, collusion or by management override of the controls in place.

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II--OTHER INFORMATION

Item 1.

Legal Proceedings.

Petrol is and may become involved in various routine legal proceedings incidental to its business. However, to Petrol’s knowledge as of the date of this report, there are no material pending legal proceedings to which Petrol is a party or to which any of its property is subject.

Item 1A. Risk Factors.

Risks Associated with Laurus Funds Financing

We have substantial indebtedness to Laurus Master Fund, Ltd. which is secured by all of our assets. If an event of default occurs under the secured notes issued to Laurus Funds, Laurus Funds may foreclose on all of our assets and we may be forced to curtail our operations or sell some or all of our assets to repay the notes.

On October 28, 2004, we entered into an $8,000,000 credit facility with Laurus Master Fund, Ltd. pursuant to a secured convertible term note and related agreements. On October 31, 2005, we entered into a $50 million credit facility with Laurus Master Fund, Ltd., pursuant to a secured note and related agreements whereby we received an initial $10,000,000. On March 31,

2006, we entered into agreements with Laurus Master Fund, Ltd. to draw down an additional $5,000,000 under the credit facility provided by Laurus on October 31, 2005. On May 31, 2006, we entered into agreements with Laurus Master Fund, Ltd. to draw down an additional $10,000,000 under the credit facility provided by Laurus on October 31, 2005. Subject to certain grace periods, the notes and agreements provide for the following events of default (among others):

Failure to pay interest and principal when due;
An uncured breach by us of any material covenant, term or condition in any of the notes or related agreements;
A breach by us of any material representation or warranty made in any of the notes or in any related agreement;
Any money judgment or similar final process is filed against us for more than $50,000;
Any form of bankruptcy or insolvency proceeding is instituted by or against us;
A change in control of our stock ownership or a majority change in control in our board of directors; and
Suspension of our common stock from our principal trading market for five consecutive days or five days during any ten consecutive days.

In the event of a future default under our agreements with Laurus Funds, Laurus Funds may enforce its rights as a secured party and we may lose all or a portion of our assets or be forced to materially reduce our business activities.

The issuance of shares to Laurus Funds upon conversion of the convertible term note and exercise of its warrants may cause immediate and substantial dilution to our existing stockholders.

The issuance of shares upon conversion of the convertible term note and exercise of warrants may result in substantial dilution to the interests of other stockholders. Laurus Funds may ultimately convert and sell the full amount issuable on conversion. Although Laurus Funds in some cases may not, subject to certain exceptions, convert their term note and/or exercise their warrants if such conversion or exercise would cause them to own more than 4.99% of our outstanding common stock, this restriction does not prevent Laurus Funds from converting and/or exercising some of their holdings and then converting the rest of their holdings. In this way, Laurus Funds could sell more than this limit while never holding more than this limit, which will have the effect of further diluting the proportionate equity interest and voting power of holders of our common stock.

It is likely at the time shares of common stock are issued to Laurus Funds, the conversion price of such securities will be less than the market price of the securities. The issuance of common stock under the terms of our agreements with Laurus Funds will result in dilution of the interests of the existing holders of common stock at the time of the conversion. Furthermore, the sale of common stock owned by Laurus Funds as a result of the conversion of the convertible term note may result in lower prices for the common stock if there is insufficient buying interest in the markets at the time of conversion.

Laurus Funds has no obligation to convert shares if the market price is less than the conversion price.

Laurus has no obligation to cause us to issue common stock if the market price is less than the applicable conversion price ($1.50). In some of the days of the second and most of the third quarter our stock price was lower than the conversion discounted price granted to Laurus. Laurus has no obligation to convert the securities or to accept common stock as payment for interest if the market price of the securities for five trading days prior to a conversion date is less than 115% the conversion price. The amount of common stock that may be issued to Laurus is subject to certain limitations based on price, volume and/or the inventory of our common stock held by Laurus.

Risks Associated with Oil and Gas Operations

Because we face uncertainties in estimating proven recoverable natural gas reserves, you should not place undue reliance on such reserve information.

Our Form 10-K (filed on April 17, 2007) contains estimates of natural gas reserves, and the future net cash flows attributable to those reserves, prepared by McCune Engineering, our independent petroleum and geological engineer. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the control of McCune Engineering. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data; assumptions regarding future natural gas and oil prices; expenditures for future development and exploitation activities; and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and natural gas and oil prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in our Form 10-K. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in our Form 10-K were prepared by McCune Engineering in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:

geological conditions;
changes in governmental regulations and taxation;
assumptions governing future prices;
the amount and timing of actual production;
availability of funds;
future operating and development costs; and
capital costs of drilling new wells.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

The SEC permits natural gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC’s guidelines strictly prohibit us from including “probable reserves” and “possible reserves” in filings with the SEC. We also caution you that the SEC views such “probable” and “possible” reserve estimates as inherently unreliable and these estimates may be seen as misleading to investors unless the reader is an expert in the natural gas industry. Unless you have such expertise, you should not place undo reliance on these estimates. Potential investors should also be aware that such “probable” and “possible” reserve estimates will not be contained in any “resale” or other registration statement filed by us that offers or sells shares on behalf of purchasers of our common stock and may have an impact on the valuation of the resale of the shares. We undertake no duty to update this information and does not intend to update the information.

Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any addition to our production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

Developing and exploring for natural gas and oil involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential additional sites that may be developed, require significant additional

exploration and development, regulatory approval and commitments of resources prior to commercial development. Any success that we may have with these wells or any future drilling operations will most likely not be indicative of our current or future drilling success rate, particularly, because we intend to emphasize on exploratory drilling. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

Development of our reserves, when established, may not occur as scheduled and the actual results may not be as anticipated. Drilling activity may result in downward adjustments in reserves or higher than anticipated costs. Our estimates will be based on various assumptions, including assumptions required by the Securities and Exchange Commission relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating our natural gas and oil reserves is anticipated to be extremely complex, and will require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Due to our inexperience in the oil and gas industry, our estimates may not be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development expenditures and operating expenses will likely vary from those anticipated. These variances may be material.

Gas and Oil prices are volatile. This volatility may occur in the future, causing negative change in cash flows which may result in our inability to cover our capital expenditures.

Our future revenues, profitability, future growth and the carrying value of our properties is anticipated to depend substantially on the prices we may realize for our natural gas and oil production. Our realized prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

Natural gas and oil prices are subject to wide fluctuations in response to relatively minor changes in or perceptions regarding supply and demand. Historically, the markets for natural gas and oil have been volatile, and they are likely to continue to be volatile in the future. For example, natural gas and oil prices declined significantly in late 1998 and 1999 and, for an extended period of time, remained substantially below prices obtained in previous years. Among the factors that can cause this volatility are:

worldwide or regional demand for energy, which is affected by economic conditions;
the domestic and foreign supply of natural gas and oil;
weather conditions;
domestic and foreign governmental regulations;
political conditions in natural gas and oil producing regions;
the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels; and
the price and availability of other fuels.

It is impossible to predict natural gas and oil price movements with certainty. Lower natural gas and oil prices may not only decrease our future revenues on a per unit basis but also may reduce the amount of natural gas and oil that we can produce economically. A substantial or extended decline in natural gas and oil prices may materially and adversely affect our future business enough to force us to cease our business operations. In addition, our financial condition, results of operations, liquidity and ability to finance planned capital expenditures will also suffer in such a price decline. Further, natural gas and oil prices do not necessarily move together.

We may incur substantial write-downs of the carrying value of our gas and oil properties, which would adversely impact our earnings.

We periodically review the carrying value of our gas and oil properties under the full cost accounting rules of the Securities and Exchange Commission. Under these rules, capitalized costs of proved gas and oil properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at an annual rate of 10%. Application of this “ceiling” test requires pricing future revenue at the un-escalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded, even if prices were depressed for only a short period of time. We may be required to write down the carrying value of our gas and oil properties when natural gas and oil prices are depressed or unusually volatile, which would result in a charge against our earnings. Once incurred, a write-down of the carrying value of our natural gas and oil properties is not reversible at a later date.

Currently the vast majority of our producing properties are located in the Cherokee Basin of southeastern Kansas, making us vulnerable to risks associated with having our production concentrated in one area.

The vast majority of our producing properties are geographically concentrated in the Cherokee Basin of southeastern Kansas. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area.

Competition in our industry is intense. We are very small and have an extremely limited operating history as compared to the vast majority of our competitors, and we may not be able to compete effectively.

We intend to compete with major and independent natural gas and oil companies for property acquisitions. We will also compete for the equipment and labor required to operate and develop natural gas and oil properties. The majority of our anticipated competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for natural gas and oil properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire

additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, some of our competitors have been operating in our core areas for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

The natural gas and oil business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas and oil well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.

The natural gas and oil business involves a variety of operating risks, including:

fires;
explosions;
blow-outs and surface cratering;
uncontrollable flows of oil, natural gas, and formation water;
natural disasters, such as hurricanes and other adverse weather conditions;
pipe, cement, or pipeline failures;
casing collapses;
embedded oil field drilling and service tools;
abnormally pressured formations; and
environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:

injury or loss of life;
severe damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
clean-up responsibilities;
regulatory investigation and penalties;
suspension of our operations; and
repairs to resume operations.

Because we intend to use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all operational risks. We do not carry business interruption

insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.

The high cost of drilling rigs, equipment, supplies, personnel and other services could adversely affect our ability to execute on a timely basis our development, exploitation and exploration plans within our budget.

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or interrupt our operations, which could impact our financial condition and results of operations. Drilling activity in the geographic areas in which we conduct drilling activities may increase, which would lead to increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in these areas may also decrease the availability of rigs. We do not have any contracts with providers of drilling rigs and we cannot assure you that drilling rigs will be readily available when we need them. Drilling and other costs may increase further and necessary equipment and services may not be available to us at economical prices.

Our lease ownership may be diluted due to financing strategies we may employ in the future due to our lack of capital or due to our focus on producing leases.

To accelerate our development efforts we plan to take on working interest partners that will contribute to the costs of drilling and completion and then share in revenues derived from production. In addition, we may in the future, due to a lack of capital or other strategic reasons, establish joint venture partnerships or farm out all or part of our development efforts. These economic strategies may have a dilutive effect on our lease ownership and will more than likely reduce our operating revenues.

In addition, our lease ownership is subject to forfeiture in the event we are unwilling or unable to continue making lease payments. Our leases vary in price per acre and on the term period of the lease. Each lease requires payment to maintain an active lease. In the event we are unable or unwilling to make our lease payments or renew expiring leases, then we will forfeit our rights to such leases. Such forfeiture would prevent us from pursuing development activity on the leased property and could have a substantial impact on our gross leased acreage.

We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Development, production and sale of natural gas and oil in the United States are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

location and density of wells;
the handling of drilling fluids and obtaining discharge permits for drilling operations;
accounting for and payment of royalties on production from state, federal and Indian lands;
bonds for ownership, development and production of natural gas and oil properties;
transportation of natural gas and oil by pipelines;
operation of wells and reports concerning operations; and
taxation.

Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations enough to possibly force us to cease our business operations.

Our oil and gas operations may expose us to environmental liabilities.

Any leakage of crude oil and/or gas from the subsurface portions of our wells, our gathering system or our storage facilities could cause degradation of fresh groundwater resources, as well as surface damage, potentially resulting in suspension of operation of the wells, fines and penalties from governmental agencies, expenditures for remediation of the affected resource, and liabilities to third parties for property damages and personal injuries. In addition, any sale of residual crude oil collected as part of the drilling and recovery process could impose liability on us if the entity to which the oil was transferred fails to manage the material in accordance with applicable environmental health and safety laws.

Risks Associated with Our Business

Our auditor’s report reflects the fact that without realization of additional capital, it would be unlikely for us to continue as a going concern.

As a result of our deficiency in working capital at March 31, 2007 and December 31, 2006 and other factors, our auditors have included an explanatory paragraph in their audit report regarding substantial doubt about our ability to continue as a going concern. The financial statements do not include any adjustments as a result of this uncertainty. The going concern qualification may adversely impact our ability to raise the capital necessary for the expansion and continuation of operations.

Our internal controls may be inadequate, which could cause our financial reporting to be unreliable and lead to misinformation being disseminated to the public.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. As defined in Exchange Act Rule 13a-15(f), internal control over financial reporting is a process designed by, or under the supervision of, the principal executive and principal financial officer and effected by the board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of Petrol; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of Petrol are being made only in accordance with authorizations of management and directors of Petrol, and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Petrol’s assets that could have a material effect on the financial statements.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Further, we have a limited number of personnel that are required to perform various roles and duties as well as be responsible for monitoring and ensuring compliance with our internal control procedures. As a result, our internal controls may be inadequate or ineffective, which could cause our financial reporting to be unreliable and lead to misinformation being disseminated to the public. Any failure to develop or maintain effective internal controls or difficulties encountered in implementing or improving our internal controls could harm operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls also could cause our stockholders and potential investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock. In addition, investors relying upon this misinformation may make an uninformed investment decision.

We may need additional capital in the future to finance our planned growth, which we may not be able to raise or it may only be available on terms unfavorable to us or our stockholders, which may result in our inability to fund our working capital requirements and harm our operational results.

We have had substantial capital expenditure and working capital needs associated with the development of our Coal Creek Project. We believe that current cash on hand and the other sources of liquidity are only sufficient enough to fund our operations through fiscal 2007. After that time we will need to rely on cash flow operations or raise additional cash to fund our operations, to fund our anticipated reserve replacement needs and implement our growth strategy, or to respond to competitive pressures and/or perceived opportunities, such as investment, acquisition, exploration and development activities.

If low natural gas and oil prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues or cash flows from operations to decrease, we may be

limited in our ability to spend the capital necessary to complete our development, production exploitation and exploration programs. If our resources or cash flows do not satisfy our operational needs, we will require additional financing, in addition to anticipated cash generated from our operations, to fund our planned growth. Additional financing might not be available on terms favorable to us, or at all. If adequate funds were not available or were not available on acceptable terms, our ability to fund our operations, take advantage of unanticipated opportunities, develop or enhance our business or otherwise respond to competitive pressures would be significantly limited. In such a capital restricted situation, we may curtail our acquisition, drilling, development, and exploration activities or be forced to sell some of our assets on an untimely or unfavorable basis.

If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our stockholders would be reduced, and these newly issued securities might have rights, preferences or privileges senior to those of existing stockholders.

Shortages of natural gas and oil field service personnel and equipment could adversely affect our business.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Due to recent high natural gas and oil prices, we have experienced shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. Higher natural gas and oil prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services and personnel in our exploration and production operations. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted.

Risk Factors Relating to Our Common Stock

If we fail to remain current on our reporting requirements, we could be removed from the OTC Bulletin Board which would limit the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.

Companies trading on the OTC Bulletin Board, such as us, must be reporting issuers under Section 12 of the Securities Exchange Act of 1934, as amended, and must be current in their reports under Section 13, in order to maintain price quotation privileges on the OTC Bulletin Board. More specifically, NASD has enacted Rule 6530, which determines eligibility of issuers quoted on the OTC Bulletin Board by requiring an issuer to be current in its filings with the Commission. Pursuant to Rule 6530(e), if we file our reports late with the Commission three times in a two-year period or our securities are removed from the OTC Bulletin Board for failure to timely file twice in a two-year period then we will be ineligible for quotation on the OTC Bulletin Board. As a result, the market liquidity for our securities could be severely adversely affected by limiting the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.

Because our common stock is deemed a low-priced “Penny” stock, an investment in our common stock should be considered high risk and subject to marketability restrictions.

Since our common stock is a penny stock, as defined in Rule 3a51-1 under the Securities Exchange Act, it will be more difficult for investors to liquidate their investment even if and when a market develops for the common stock. Until the trading price of the common stock rises above $5.00 per share, if ever, trading in the common stock is subject to the penny stock rules of the Securities Exchange Act specified in rules 15g-1 through 15g-10. Those rules require broker-dealers, before effecting transactions in any penny stock, to:

Deliver to the customer, and obtain a written receipt for, a disclosure document;
Disclose certain price information about the stock;
Disclose the amount of compensation received by the broker-dealer or any associated person of the broker-dealer;
Send monthly statements to customers with market and price information about the penny stock; and
In some circumstances, approve the purchaser’s account under certain standards and deliver written statements to the customer with information specified in the rules.

Consequently, the penny stock rules may restrict the ability or willingness of broker-dealers to sell the common stock and may affect the ability of holders to sell their common stock in the secondary market and the price at which such holders can sell any such securities. These additional procedures could also limit our ability to raise additional capital in the future.

NASD sales practice requirements may also limit a stockholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, the National Association of Securities Dealers (NASD) has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, the NASD believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The NASD requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

We could be subject to class action litigation due to stock price volatility, which, if occurs, could result in substantial costs or large judgments against us.

The market for our common stock may experience extreme price and volume fluctuations, which may be unrelated or disproportionate to our operating performance or

prospects. In the past, securities class action litigation has often been brought against companies following periods of volatility in the market prices of their securities. We may be the target of similar litigation in the future. Securities litigation could result in substantial costs and divert our management’s attention and resources, which could have a negative effect on our business, operating results and financial condition.

Our common stock is an unsecured equity interest.

As an equity interest, our common stock will not be secured by any of our assets. Therefore, in the event of our liquidation, the holders of the common stock will receive a distribution only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution to the holders of the common stock.

Our Articles of Incorporation authorizes our Board of Directors to issue up to 10,000,000 shares of preferred stock, which could adversely affect the voting power of our common stock holders.

Our Board of Directors is authorized, without further approval of our stockholders, to fix the dividend rights and terms, conversion rights, voting rights, redemption rights and terms, liquidation preferences, and any other rights, preferences, privileges and restrictions applicable to our preferred stock. The issuance of such stock could adversely affect the voting power of the holders of Common Stock and, under certain circumstances, make it more difficult for a third party to gain control of Petrol, discourage bids for the common stock at a premium, or otherwise adversely affect the market price of the common stock.

Provisions in Nevada law could delay or prevent a change in control, even if that change would be beneficial to our stockholders.

Certain provisions of Nevada law may delay, discourage, prevent or render more difficult an attempt to obtain control of Petrol, whether through a tender offer, business combination, proxy contest or otherwise. The provisions of Nevada law are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of Petrol to first negotiate with our board of directors.

The Nevada Revised Statutes (the “NRS”) contain two provisions, described below as “Combination Provisions” and the “Control Share Act,” that may make more difficult the accomplishment of unsolicited or hostile attempts to acquire control of Petrol through certain types of transactions.

Restrictions on Certain Combinations Between Nevada Resident Corporations and Interested Stockholders. The NRS includes the Combination Provisions prohibiting certain “combinations” (generally defined to include certain mergers, disposition of assets transactions, and share issuance or transfer transactions) between a resident domestic corporation and an “interested stockholder” (generally defined to be the beneficial owner of 10% or more of the voting power of the outstanding shares of the corporation), except those combinations which are

approved by the board of directors before the interested stockholder first obtained a 10% interest in the corporation’s stock. There are additional exceptions to the prohibition, which apply to combinations if they occur more than three years after the interested stockholder’s date of acquiring shares. The Combination Provisions apply unless the corporation elects against their application in its original articles of incorporation or an amendment thereto. Our articles of incorporation do not currently contain a provision rendering the Combination Provisions inapplicable.

Nevada Control Share Act. Nevada’s Control Share Act imposes procedural hurdles on and curtails greenmail practices of corporate raiders. The Control Share Act temporarily disenfranchises the voting power of “control shares” of a person or group (“Acquiring Person”) purchasing a “controlling interest” in an “issuing corporation” (as defined in the NRS) not opting out of the Control Share Act. In this regard, the Control Share Act will apply to an “issuing corporation”, unless the articles of incorporation or bylaws in effect on the tenth day following the acquisition of a controlling interest provide that it is inapplicable. Our articles of incorporation and bylaws do not currently contain a provision rendering the Control Share Act inapplicable.

Under the Control Share Act, an “issuing corporation” is a corporation organized in Nevada which has 200 or more stockholders of record, at least 100 of whom have addresses in that state appearing on the company’s stock ledger, and which does business in Nevada directly or through an affiliated company. Our status at the time of the occurrence of a transaction governed by the Control Share Act (assuming that our articles of incorporation or bylaws have not theretofore been amended to include an opting out provision) would determine whether the Control Share Act is applicable. We currently conduct business in Nevada through an executive office located in Las Vegas, Nevada.

The Control Share Act requires an Acquiring Person to take certain procedural steps before he or it can obtain the full voting power of the control shares. “Control shares” are the shares of a corporation (1) acquired or offered to be acquired which will enable the Acquiring Person to own a “controlling interest,” and (2) acquired within 90 days immediately preceding that date. A “controlling interest” is defined as the ownership of shares which would enable the Acquiring Person to exercise certain graduated amounts (beginning with one-fifth) of all voting power of the corporation in the election of directors. The Acquiring Person may not vote any control shares without first obtaining approval from the stockholders not characterized as “interested stockholders” (as defined below).

To obtain voting rights in control shares, the Acquiring Person must file a statement at the principal office of the issuer (“Offeror’s Statement”) setting forth certain information about the acquisition or intended acquisition of stock. The Offeror’s Statement may also request a special meeting of stockholders to determine the voting rights to be accorded to the Acquiring Person. A special stockholders’ meeting must then be held at the Acquiring Person’s expense within 30 to 50 days after the Offeror’s Statement is filed. If a special meeting is not requested by the Acquiring Person, the matter will be addressed at the next regular or special meeting of stockholders.

At the special or annual meeting at which the issue of voting rights of control shares will be addressed, “interested stockholders” may not vote on the question of granting voting rights to control the corporation or its parent unless the articles of incorporation of the issuing corporation provide otherwise. Our articles of incorporation and bylaws do not currently contain a provision allowing for such voting power.

If full voting power is granted to the Acquiring Person by the disinterested stockholders, and the Acquiring Person has acquired control shares with a majority or more of the voting power, then (unless otherwise provided in the articles of incorporation or bylaws in effect on the tenth day following the acquisition of a controlling interest) all stockholders of record, other than the Acquiring Person, who have not voted in favor of authorizing voting rights for the control shares, must be sent a notice advising them of the fact and of their right to receive “fair value” for their shares. Our articles of incorporation and bylaws do not provide otherwise. By the date set in the dissenter’s notice, which may not be less than 30 nor more than 60 days after the dissenter’s notice is delivered, any such stockholder may demand to receive from the corporation the “fair value” for all or part of his shares. “Fair value” is defined in the Control Share Act as “not less than the highest price per share paid by the Acquiring Person in an acquisition.”

The Control Share Act permits a corporation to redeem the control shares in the following two instances, if so provided in the articles of incorporation or bylaws of the corporation in effect on the tenth day following the acquisition of a controlling interest: (1) if the Acquiring Person fails to deliver the Offeror’s Statement to the corporation within 10 days after the Acquiring Person’s acquisition of the control shares; or (2) an Offeror’s Statement is delivered, but the control shares are not accorded full voting rights by the stockholders. Our articles of incorporation and bylaws do not address this matter.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

On January 30, 2007, we issued 6,329 shares of our restricted common stock to ECON Investor Relations, Inc., as final payment for the services performed pursuant to its consulting agreement dated June 15, 2004. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2). The recipient of the shares was afforded an opportunity for effective access to files and records of Petrol that contained the relevant information needed to make its investment decision, including Petrol’s financial statements and 34 Act reports. We reasonably believe that the recipient, immediately prior to issuing the shares, had such knowledge and experience in its financial and business matters that it was capable of evaluating the merits and risks of its investment. The recipient had the opportunity to speak with our president and directors on several occasions prior to its investment decision.

Pursuant to Paul Branagan’s resignation as the Company’s President and Chief Executive Officer on May 4, 2007 and his resignation and retirement agreement, 1,750,000 options to purchase shares of our common stock were cancelled.

Issuer Purchases of Equity Securities

Petrol did not repurchase any of its equity securities during the three months ended March 31, 2007.

Item 3.

Defaults Upon Senior Securities.

None.

Item 4.

Submission of Matters to a Vote of Security Holders.

None.

Item 5.

Other Information.

Departure of Directors and Principal Officer and Appointment of New Principal Officer

On May 4, 2007, Paul Branagan, our President and Chief Executive Officer, retired as an officer and director of the Company, citing health reasons. The Company is not aware of any disagreement Mr. Branagan may have with the Company on any matter relating to the Company’s operations, policies or practices. In connection with Mr. Branagan’s retirement, the Company entered into a Retirement Agreement with Mr. Branagan providing (1) six months of salary continuation and 18 months of health benefits, (2) termination of the employment agreement between Mr. Branagan and the Company, (3) the release by Mr. Branagan of his 1% overriding royalty interest in Company oil and gas production, and (4) mutual releases of claims. A copy of the Retirement Agreement was attached as Exhibit 10.1 to our Form 8-K filed on May 8, 2007.

On May 4, 2007, Suzanne Herring resigned as a director of the Company. The Company is not aware of any disagreement Ms. Herring may have with the Company on any matter relating to the Company’s operations, policies or practices.

On May 4, 2007, Loren W. Moll, our current Chairman of the Board, was appointed interim President and Chief Executive Officer of the Company by the Board of Directors. Information regarding Mr. Moll’s business experience and relationships with the Company is included in our Annual Report on Form 10-K, Items 10 and 13, filed on April 17, 2007, for the Company’s year ended December 31, 2006.

Mr. Moll previously indicated his intention not to stand for re-election to the Board at the next annual meeting of stockholders. On May 4, 2007, Mr. Moll informed the Board that he is now willing to stand for re-election to the Board at the next annual meeting of stockholders.

Other Events

On May 4, 2007, our Board of Directors took the following actions intended to enhance the Company’s corporate governance:

The reconstitution of the Audit Committee with independent directors Robert Kite and Duane Fadness;

The adoption of a new Amended and Restated Charter of the Audit Committee, which was filed as Exhibit 99.1 to our Form 8-K filed on May 8, 2007;
The establishment of a Compensation Committee comprised of directors Duane Fadness and Robert Kite;
The adoption of a new Charter of the Compensation Committee, which was filed as Exhibit 99.2 to our Form 8-K filed on May 8, 2007;
The reconstitution of the Nominating and Corporate Governance Committee comprised of directors Robert Kite and Loren Moll;
The adoption of a new Amended and Restated Charter of the Nominating and Corporate Governance Committee, which was filed as Exhibit 99.3 to our Form 8-K filed on May 8, 2007;
The establishment of an Executive Committee consisting of Robert Kite and Loren Moll, to act on behalf of the Board of Directors when it is not in session;
The adoption of new Corporate Governance Guidelines, which was filed as Exhibit 99.4 to our Form 8-K filed on May 8, 2007.
The adoption of new Complaint Policy and Procedures, which was filed as Exhibit 99.5 to our Form 8-K filed on May 8, 2007.

Press Releases

On May 7, 2007, we issued a press release announcing the actions taken by the Board at its meeting held on May 4, 2007. The press release was filed as Exhibit 99.6 to our Form 8-K filed on May 8, 2007.

On May 10, 2007, we issued a press release to announce that Kenton L. Hupp and Stephen P. Clark have been engaged as consultants to assist the Company’s operating management team. A copy of the press release is attached hereto as Exhibit 99.9.

Item 6.

Exhibits.

Incorporated by reference

Exhibit

number

Exhibit description

Filed

herewith

Form

Period

ending

Exhibit No.

Filing

date

Asset Purchase Agreement between Petrol Energy, Inc. and Euro Technology Outfitters, August 19, 2002

SB-2

1/22/03

3i(a)

Certificate of Amendment of Articles of Incorporation of Euro Technology Outfitters, filed on August 20, 2002

SB-2

3(i)(a)

1/22/03

3i(b)

Articles of Incorporation for Euro Technology Outfitters, filed on March 3, 2000

SB-2

3(i)(b)

1/22/03

3ii

Bylaws for Euro Technology Outfitters

SB-2

3(ii)

1/22/03

10.1

Amendment to Translation and Business Consulting agreement with Goran Blagojevic dated December 20, 2002

SB-2

10.1

1/22/03

10.2

Service and Water Disposal Agreement dated November 15, 2002

SB-2

10.2

1/22/03

10.3

Employment agreement with Paul Branagan dated December 19, 2002

SB-2

10.3

1/22/03

10.4

Geologist/Technical Advisor Consulting Agreement with William Stoeckinger dated December 19, 2002

SB-2

10.4

1/22/03

10.5

Land Services Consulting Agreement with Russell Frierson dated December 27, 2002

SB-2

10.5

1/22/03

10.6

Land Services Consulting Agreement with Lawrence Kehoe dated December 27, 2002

SB-2

10.6

1/22/03

10.7

Land Services Consulting Agreement with Cody Felton dated December 27, 2002

SB-2

10.7

1/22/03

10.8

Waverly Kansas Office Lease dated January 21, 2003

SB-2

10.8

1/22/03

10.9

2002 Master Stock Option Plan

SB-2

10.9

1/22/03

10.10

Term Sheet of Compensation for Enutroff, dated 7/01/03

10-QSB

9/30/03

10.1

11/14/03

10.11

Consultant Agreement of CSC Group LLC

10-KSB

12/31/03

10.10

4/15/04

10.12

Employment Agreement of David Polay

10-KSB

12/31/03

10.11

4/15/04

10.13

Addendum to Employment Agreement of Paul Branagan

10-KSB

12/31/03

10.12

4/15/04

10.14

Employment Agreement of Gary Bridwell

10-KSB

12/31/03

10.13

4/15/04

10.15

Letter Agreement with William D. Burke

10-KSB

12/31/03

10.14

4/15/04

10.16

Purchase and Sale Agreement with CBM Energy Inc.

10-KSB

12/31/03

10.15

4/15/04

10.17

Research Agreement with Joseph E. Blankenship

10-KSB

12/31/03

10.16

4/15/04

10.18

Research Agreement Scope of Work and Compensation

10-KSB

12/31/03

10.17

4/15/04

10.19

Business Partnership Term Sheet with John Haas, Mark Haas, and W.B. Mitchell

10-KSB

12/31/03

10.18

4/15/04

10.20

Addendum #2 Employment Agreement of Paul Branagan

10-QSB

3/31/04

10.6

5/17/04

10.21

Securities Purchase Agreement for Laurus

SB-2

10.21

2/7/05

10.22

Registration Rights Agreement for Laurus

SB-2

10.22

2/7/05

10.23

Subscription and Registration Rights Agreement for Unit Offering

SB-2

10.23

2/7/05

10.24

Warrant Agreement for Unit Offering

SB-2

10.24

2/7/05

10.25

Amendment No. 1 to the Secured Convertible Term Note & Registration Rights Agreement with Laurus, dtd 1/28/05

SB-2

10.25

2/7/05

10.26

Common Stock Purchase Warrant of Laurus, dated 01/28/05

SB-2

10.26

2/7/05

10.27

Letter Amendment Agreement with Laurus, dated 04/28/05

SB-2

10.27

5/12/05

10.28

Consulting Agreement with CEOcast, dated 08/7/04

SB-2

10.28

5/12/05

10.29

Amendment No. 1 to October 2004 Securities Purchase Agreement

SB-2

10.29

12/1/05

10.30

Securities Purchase Agreement dated October 31, 2005

SB-2

10.30

12/1/05

10.31

Secured Term Note dated October 31, 2005

SB-2

10.31

12/1/05

10.32

Common Stock Purchase Warrant dated October 31, 2005

SB-2

10.32

12/1/05

10.33

Registration Rights Agreement dated October 31, 2005

SB-2

10.33

12/1/05

10.34

Amended and Restated Mortgage

SB-2

10.34

12/1/05

10.35

Retirement Agreement of Paul Branagan dated May 4, 2007

8-K

10.1

5/8/07

21.1

List of Subsidiaries of Petrol Oil and Gas, Inc.

10-KSB

12/31/05

3/31/06

21.2

List of Subsidiaries of Petrol Oil and Gas, Inc. – December 31, 2006

10-K

12/31/07

21.2

4/17/07

Certification of Loren Moll pursuant to Section 302 of the Sarbanes-Oxley Act.

Certification of Loren Moll pursuant to Section 906 of the Sarbanes-Oxley Act.

99.1

Audit Committee Charter

10-KSB

12/31/05

3/31/06

99.2

Governance and Nominating Committee Charter

10-K

12/31/06

99.2

4/17/07

99.3

Amended and Restated Charter of Audit Committee

8-K

��

99.1

5/8/07

99.4

Charter of the Compensation Committee

8-K

99.2

5/8/07

99.5

Amended and Restated Charter of the Nominating and Corporate Governance Committee

8-K

99.3

5/8/07

99.6

Corporate Governance Guidelines

8-K

99.4

5/8/07

99.7

Complaint Policy and Procedures

8-K

99.5

5/8/07

99.8

Press Release issued May 7, 2007

8-K

99.6

5/8/07

99.9

Press Release issued May 10, 2007

SIGNATURES

Pursuant to the requirements 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.

PETROL OIL AND GAS, INC.

(Registrant)

By:/s/ Loren Moll

Loren Moll, Chief Executive Officer

(On behalf of the registrant and as

principal accounting officer)

Date: May 15, 2007

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Good

Petrol Oil & Gas (POIG) Inactive 10-Q2007 Q1 Quarterly report

Content analysis