Petrol Oil & Gas (POIG) 10-Q/A 2006 Q1 Quarterly report (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2006

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 110th Street, Suite 500
Overland Park, Kansas	66210
(Address of principal executive offices)	(Zip Code)

(913) 323-4925

(Registrant’s telephone number, including area code)

Copies of Communications to:

Stoecklein Law Group

402 West Broadway, Suite 400

San Diego, CA 92101

(619) 595-4882

Fax (619) 595-4883

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 5, 2006, was 28,630,419 shares.

* We are filing this Amendment No. 1 to Form 10-Q to amend our Quarterly Report on Form 10-Q for the period March 31, 2006, (the "Original Filing") filed on May 22, 2006, with the Securities and Exchange Commission in order to revise certain financial statement disclosure related to options issued for consulting services.

This Amendment does not amend any other information previously filed in the Original Filing.The Original Filing is hereby superseded and amended with respect to Part I, Items 1, 2 and 4 set forth in this Amendment No. 1.

PART I -- FINANCIAL INFORMATION

Item 1. Financial Statements.

Petrol Oil and Gas, Inc.

Condensed Consolidated Balance Sheet

(unaudited)

	March 31,
	2006
Assets
Current assets:
Cash	$	1,321,771
Accounts receivable		765,561
Total current assets		2,087,332
Fixed assets, net		4,068,531
Other assets:
Oil and gas properties using full cost accounting:
Properties not subject to amortization		1,021,175
Properties subject to amortization		17,746,450
Capitalized loan costs, net		650,193
Derivative asset		788,633
Total other assets		20,206,451
	$	26,362,314
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable		649,951
Accrued liabilities		227,179
Asset retirement obligation		792,060
Current portion of long term debt		3,212,132
Total liabilities		4,881,322
Long-term debt, less current portion		10,830,270
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, 28,318,471 shares issued and outstanding at 3/31/06		28,318
Stock bought or for services not issued, 11,512 shares at 3/31/06		12
Unamortized cost of stock, warrants & options issued for services		(2,086,451)
Additional paid-in capital		26,686,592
Other comprehensive income		788,633
Accumulated (deficit)		(14,766,382)
		10,650,722
	$	26,362,314

See notes to condensed consolidated financial statements.

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Petrol Oil and Gas, Inc.

Condensed Consolidated Statement of Operations

	For the Three Months Ended
	March 31,
	2006		2005
Revenue
Oil and gas activities	$	1,186,025	$	1,190,611
Operator fees		30,000		-
Total revenue		1,216,025		1,190,611
Expenses:
Direct costs		585,855		418,001
Pipeline costs		154,010		-
General and administrative		564,593		300,118
Professional and consulting fees		591,794		1,412,580
Depreciation, depletion and amortization		464,649		349,454
Total expenses		2,360,901		2,480,153
Net operating (loss)		(1,144,876)		(1,289,542)
Other income (expense):
Interest and other income		1,794		13,653
Interest expense		(692,114)		(395,815)
Total other income (expense)		(690,320)		(382,162)
Net (loss)	$	(1,835,196)	$	(1,671,704)
Weighted average number of common shares outstanding - basic and fully diluted		28,033,096		21,529,710
Net (loss) per share - basic and fully diluted	$	(0.07)	$	(0.08)

See notes to condensed consolidated financial statements.

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Petrol Oil and Gas, Inc.

Condensed Consolidated Statement of Cash Flows

	Three Months Ended
	March 31,
	2006		2005
Cash flows from operating activities
Net (loss)	$	(1,835,196)	$	(1,671,704)
Depreciation, depletion and amortization		480,691		349,454
Warrant accretion		260,294		255,133
Shares issued for interest		153,527		-
Stock, and warrants issued for services		472,918		1,344,087
Adjustments to reconcile net (loss) to cash
used in operating activities:
Accounts receivable		(151,747)		(480,503)
Prepaid and other assets		-		(25,511)
Accounts payable		(724,987)		(151,932)
Accrued liabilities		76,011		426,382
Net cash provided by (used in) operating activities		(1,268,489)		45,406
Cash flows from investing activities
Purchase of fixed assets		(1,661,747)		-
Additions to oil and gas properties not subject to amortization		(67,173)		-
Additional restricted cash		-		(5,421)
Additions to oil and gas properties subject to amortization		(4,257,159)		(487,702)
Net cash used in investing activities		(5,986,079)		(493,123)
Cash flows from financing activities
Payments on notes payable		(8,864)		(1,000)
Proceeds from exercising of warrants		150,000		-
Net cash provided by (used in) financing activities		141,136		(1,000)
Net decrease in cash		(7,113,432)		(448,717)
Cash – beginning		8,435,203		1,792,885
Cash – ending	$	1,321,771	$	1,344,168
Supplemental disclosures:
Interest paid	$	415,777	$	734
Income taxes paid		-		-
Non-cash transactions
Shares issued for oil & gas properties	$	60,500	$	-
Stock, warrants and options issued for services		-		1,344,087
Shares issued for debt conversion		685,146		-

See notes to condensed consolidated financial statements.

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Petrol Oil and Gas, Inc.

Notes to Condensed Financial Statements

Note 1 - Basis of Presentation

The unaudited condensed 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-QSB 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-KSB for the year ended December 31, 2005.

Note 2 - Stock Transactions and Consulting Agreements

On January 9, 2006, Laurus Master Fund, Ltd. converted $54,287 of accrued interest due under the Convertible Term Note. Pursuant to the conversion rate of $1.50 per share the Company issued 36,192 shares of its common stock to Laurus.

On January 18, 2006, Laurus Master Fund, Ltd. converted $228,382 of principal per the terms of the Convertible Term Note. Pursuant to the conversion rate of $1.50 per share the Company issued 152,225 shares of its common stock to Laurus.

On February 8, 2006, we issued 546,342 shares of its common stock as previously authorized for the purchase of working interests in producing wells.

On February 8, 2006, we issued 57,595 previously authorized shares of its common stock.

On February 8, 2006, Laurus Master Fund, Ltd. converted $150,000 of principal per the terms of the Convertible Term Note. Pursuant to the conversion rate of $1.50 per share the Company issued 100,000 shares of its common stock.

On February 9, 2006, Laurus Master Fund, Ltd. converted $37,500 of principal per the terms of the Convertible Term Note. Pursuant to the conversion rate of $1.50 per share the Company issued 25,000 shares of its common stock.

On February 14, 2006, Laurus Master Fund, Ltd. converted $40,882 of principal and $52,989 of accrued interest and principal due under the Convertible Term Note. Pursuant to the conversion rate of $1.50 per share the Company issued 62,581 shares of its common stock to Laurus.

On February 16, 2006, we issued 40,334 shares of its common stock in exchange for working interest in producing wells valued at $60,500.

On February 17, 2006, Laurus Master Fund, Ltd. converted $228,382 of principal per the terms of the Convertible Term Note. Pursuant to the conversion rate of $1.50 per share the Company issued 152,255 shares of its common stock to Laurus.

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Petrol Oil and Gas, Inc.

Notes to Condensed Financial Statements

On March 9, 2006, Laurus Master Fund, Ltd. converted $46,251 of accrued interest due under the Convertible Term Note. Pursuant to the conversion rate of $1.50 per share the Company issued 30,834 shares of its common stock to Laurus.

On January 1, 2006, we entered into a one year agreement with R. J. Falkner whereby we granted Mr. Falkner 110,000 options at a strike price of $1.76 exercisable for a period of thirty-six months. The value of the option was $104,004 and was recorded as unamortized cost of stock, warrants and options issued for services and will be amortized over the twelve-month term of the agreement. As of March 31, 2006, we expensed $26,001 as consulting fees.

On February 22, 2006, we issued 100,000 shares of its common stock for the exercise of warrants in exchange for cash totaling $150,000.

A summary of stock options and warrants is as follows:

	Options		Warrants
Outstanding 12/31/05	2,775,000	$1.68	18,491,666	$1.78
Granted	110,000	1.76	-	-
Cancelled	-	-	-	-
Exercised	-	-	100,000	1.50
Outstanding 3/31/06	2,885,000	$1.68	18,391,666	$1.79

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.

	March 31, 2006
Asset retirement obligation, beginning of year	$ 749,618
Liabilities incurred during the year	26,400
Liabilities settled during the year	--
Accretion of expense	16,042
Asset retirement obligations, end of year	$ 792,060

Note 4 - Long-Term Debt

Long-term debt consists of the following:

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Petrol Oil and Gas, Inc.

Notes to Condensed Financial Statements

	March 31, 2006
Total notes payable	$ 15,522,601
Less unamortized cost of warrants	(1,480,199)
	14,042,402
Less current portion	(3,212,132)
Total long-term debt	$ 10,830,270

During the quarter ended March 31, 2006, the accretion of the warrants that was included in interest expense totaled $260,294.

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, 2006 we had contracts covering approximately 60,000 mmbtu per month for the period of April 2006 to March 2007 at an average price of $8.73 per mmbtu. We also have contracts for oil production for April 2006 through July 2006 covering 660 barrels per month at an average price of $55.80.

Note 6 - Subsequent Events

On March 31, 2006, Petrol Oil and Gas, Inc. (“the Company”) entered into agreements with Laurus Master Fund, Ltd., a Cayman Islands corporation (“Laurus Funds”) to draw down an additional $5,000,000 under the credit facility provided by Laurus Funds in October 2005. Under the terms of the Laurus Funds agreements the Company issued a Secured Term Note (the “Note”) in the aggregate principal amount of $5 million and a five-year warrant (the “Warrant”) to purchase 200,000 shares of the Company’s common stock at $1.80 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 3.25%, subject to a floor of 10% and a ceiling of 14% per annum. Concurrently with the agreements listed above, the Company amended and restated its previous $10 million Secured Term Note dated October 31, 2005 with Laurus Funds.

On April 7, 2006, the funds were released from Escrow. Net proceeds to the Company from the financing, after payment of fees and expenses to Laurus Funds and its affiliates, were $4,806,687.50. The proceeds will be utilized by the Company for drilling activities on the Company’s Coal Creek Project.

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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 or 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 or 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:

• 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;

• 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 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

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We are an oil and gas exploration, development and production company. Our properties are located in the Cherokee Basin along the Kansas and Missouri border. Our corporate strategy is to continue building value in the Company 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.

Our recent activities include the consolidation of a strong lease position in CBM that contains quality proven gas reserves, some of which are adjacent to interstate pipeline systems which provide ready access to sales market for our produced gas. During 2005 our focus turned to developing and producing those leases so as to realize the value held within their reserves. With 165,000 gross leased acres (132,000 net acres) the task of developing the properties with wells on 160 acre spacing will involve in excess of 1,000 wells. Petrol holds a 100 % working interest and an average 80% net revenue interest in these leases. In order to develop this large resource base we have segregated our leases into five separate Projects which include:

1. Petrol-Neodesha Project - a 10,000 gross acre (8,000 net acres) gas producing property

2. Coal Creek Project - current development of about 92,000 gross acres (73,000 net acres) with 40 production wells, 2 salt water disposals wells and gas gathering infrastructure.

3. Pomona Project – 35,000 gross acres (28,000 net acres) with 17 shut in production wells, 1 salt water disposal well and some gas gathering infrastructure.

4. Missouri Project – 18,000 gross acres (12,000 net acres) with 5 test/evaluation wells.

5. Oil Field Projects – 10,000 gross acres

Petrol-Neodesha Project

Currently our gas producing leases known as Petrol-Neodesha, in the Neosho and Wilson counties, account for approximately 10,000 of the total 165,000 gross leased acres. These properties are in active production with on average 90 CBM producing wells that produce approximately 2.7 Million cubic feet of gas per day. Studies to drill additional wells, improve existing wells and enhance the gas gathering system have been refined into an advanced development plan and execution of the plan is in process. This plan was designed to serve as the blueprint to enhance the Net Asset Value of these properties, increase production revenue and provide knowledge for development of remaining leases in this and our other Project areas. These Petrol-Neodesha properties have provided us with a revenue stream and certain value in proven producing reserves.

We implemented Phase I of our development plan that involved expanding the production of our existing gas gathering pipeline system and drilling several new production wells. Phase I pipeline enhancements included adding approximately 3.5 miles of high capacity gas gathering pipeline and strategically incorporating 2 new booster stations to reduce pipeline pressure as well as to provide a higher level of compressor redundancy. In addition, the reduced pipeline pressure was designed to increase production from existing production wells and in fact overall field production was found to increase by about 425 Mcfd. Furthermore, the capacity of the main pipeline gathering lines was doubled and will serve to accommodate production from 50 to 100 new development wells.

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The second element of the Phase I development plan involved drilling five new CBM wells. The initial production rates were about 150 Mcfd after approximately six weeks of de-watering. These wells were the first set of wells we completed and connected to the newly enhanced gas gathering pipeline system.

We acquired an additional 400 gross acres adjacent to our Petrol-Neodesha property and drilled four new production wells during the later half of 2005 on these newly acquired leases.

We have incorporated a new gas processing unit into our Neodesha pipeline system to support growing gas sales from our Petrol-Neodesha property and enhance gas quality.

We intend to continue seeking acquisition opportunities which compliment our current production. We intend to fund our development activity primarily through the use of cash flow from operations and cash on hand, while seeking larger debt funding opportunities sufficient enough to develop a greater portion of our mineral leases. We have drilled, completed and began production from 14 new wells. On average we have included 3 new production wells per month in Petrol-Neodesha since we began implementing our drilling-development plan in late mid-2005 and have continued that new well monthly rate into 2006. Based on our current field production levels, we plan to aggressively develop future production activities.

Coal Creek Project

During 2005 Petrol embarked on securing funds for the development of our Coal Creek project centered in Coffey County, Kansas. The Coal Creek Project includes leases covering about 92,000 gross acres. In October we finalized an agreement and other documents whereby Laurus Master Funds, Ltd. would provide a debt facility of up to $50,000,000 with the first $10,000,000 tranche received in November 2005.

The Coal Creek development plan is based upon drilling and completing some 540 wells over a two to three year period along with miles of gas gathering pipelines and infrastructure to process, transport and sell gas in mid-west markets. To better manage the development of this large acreage position and take advantage of the three interstate pipeline that cross our leases we divide the project into three fully self contained areas:

1. Burlington Area – about 15,000 gross acres located in southwestern Coffey County, Kansas. This was our assessment area in which we drilled our first test wells.

2. Waverly Area – about 40,000 gross acres located in northeastern Coffey County, Kansas, Southern Osage County and Western Anderson County, Kansas.

3. Lebo Area – about 37,000 acres located in northwestern Coffey County, Kansas.

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The full development plan is expected to be executed in two phases. The first phase involves emplacing the basic gas gathering pipeline infra-structures and developing about 180 new CBM wells. Phase two includes finalizing the gas gathering pipeline and developing 360 new CBM wells. The anticipated costs of the full development plan are expected to be approximately $66,000,000. The pace of the development will obviously depend on the availability of the financing program, lender restrictions, general economic conditions, and potential other factors relevant to this type of development plan.

The first $10,000,000 tranche broke escrow in November 2005 and has been used primarily to initiate Phase I development which involved drilling gas production wells as well as the installation of a gas gathering pipeline system in both the Burlington and Waverly areas. At the end of December 2005 there were 22 production and 2 salt water disposal wells ready for connection to the gas gathering pipelines that were being installed in the Burlington area. Similarly, at the end of 2005 the first several production wells and salt water disposal well were emplaced and the gas gathering lines were being buried in the Waverly area.

On April 10, 2006, we issued a press release announcing that gas production from the Burlington area of our Coal Creek Project began flowing into the Enbridge Interstate pipeline on April 4, 2006.

On April 18, 2006, we issued a press release announcing the recent closing of escrow on an additional $5 million to support our expanded drilling program on our Coal Creek Project. This is the second funding tranche in an agreement with Laurus Master Funds to provide debt financing of up to $50 million.

Pomona Project

Located primarily in Franklin County, Kansas the Pomona Project includes leases covering about 35,000 acres. There are about 17 shut in production wells, a salt water disposal well and portions of a gas gathering infrastructure. Two interstate pipeline systems cross through our leases.

Missouri Project

Located in Cass and Bates Counties, Missouri, our Missouri Project includes leases covering about 15,000 gross acres. We drilled and tested 5 evaluation wells on our lease that abut an interstate pipeline system.

Oil Field Project

We have a 100 % working interest in several oil producing properties that produce an average 80 barrels of oil per day. These oil producing wells are generally defined as stripper wells and are producing under the influence of a water flood.

Results of Operations

The following overview provides a summary of key information concerning our financial results for the three months ended March 31, 2006 and 2005, respectively.

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	Three Months Ended March 31,
	2006	2005	Increase / (Decrease)
	Amount	Amount	$	%
Revenue
Oil and gas activities	$1,186,025	$1,190,611	(4,586)	-
Operator fees	30,000	-	30,000	-
Total revenue	1,216,025	1,190,611	25,414	2%
Expenses:
Direct costs	585,855	418,001	167,854	40%
Pipeline costs	154,010	-	154,010	-
General and administrative	564,593	300,118	264,475	88%
Professional and consulting fees	591,794	1,412,580	(820,786)	(58%)
Depreciation, depletion and amortization	464,649	349,454	115,195	33%
Total expenses	2,360,901	2,480,153	(119,252)	(4%)
Net operating (loss)	(1,144,876)	(1,289,542)	(144,666)	(11%)
Other income (expense):
Interest and other income	1,794	13,653	(11,859)	(87%)
Interest expense	(692,114)	(395,815)	296,299	75%
Total other income (expense)	(690,320)	(382,162)	308,158	81%
Net loss	$(1,835,196)	$(1,671,704)	163,492	10%

Three Months Ended on March 31, 2006 Compared to Three Months Ended on March 31, 2005

Revenue: Total revenue was $1,216,025 and $1,190,611 for the first quarter of 2006 and 2005, respectively, for an increase of $25,414 or 2%. The increase in revenues is a result of operating fees received on properties managed. The fixed price of our gas sales will be significantly higher in the remaining quarters of 2006.

Direct costs are the costs associated with operating producing wells, and transporting the oil and natural gas to the market for sale. Direct costs totaled $585,855 and $418,001 for the first quarter of 2006 and 2005, respectively, for an increase of $167,854. The increase in direct costs is primarily the result of increased costs associated with the production of gas in our Petrol-Neodesha project.

Pipeline costs totaled $154,010 and $0 for the first quarter of 2006 and 2005, respectively, for an increase of $154,010, relating to our increased production of gas in our Petrol-Neodesha project.

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General and administrative expenses for the first quarter of 2006 were $564,593 compared to $300,118 in the first quarter of 2005, respectively, for an increase of $264,475. The increase is attributable to expenses associated with additional staff and expenses related thereto as the result of our increased operations.

Professional and consulting fees were $591,794 and $1,412,580 for the first quarters of 2006 and 2005, respectively, a decrease of $820,786. The decrease is a result of using less outside consulting and professional services.

Depreciation, depletion, and amortization expense for the first quarter of 2006 and 2005 were $464,649 and $349,454 for an increase of $115,195. . The increase was a result of depreciation of our pipeline and depletion related to our production.

Other Income (Expense):

Interest and other income for the first quarter of 2006 and 2005 was $1,794 and $13,653, respectively, for a decrease of $11,859 which was the result less cash on hand earning interest income.

Interest Expense for the first quarter of 2006 and 2005 was $692,114 and $395,815, respectively, for an increase of $296,299. The increase in interest expense is the result of increased financing which we borrowed in October, 2005.

Net Loss: Our net loss for first quarter of 2006 and 2005 was $1,809,195 and $1,671,704, respectively, for an increase in net loss in the amount of $137,491.

Analysis and Discussion of Cash Flow

In the first quarter of 2006 our cash position decreased by approximately $7,113,000. The decrease was from our operating activities ($1,268,000) and our investment on the new wells and new pipelines ($5,986,000). From financing activities we netted $141,000 from a shareholder exercising warrants and cash payments on debt.

Operation Plan

During the next twelve months we plan to continue to focus our efforts on increasing Production Revenues, and enhancing our Net Asset Value. 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,

• aggressive development of our 92,000 gross acre Coal Creek Project,

• pursuing strategic acquisitions of producing properties and;

• creating value by furthering our business plan.

Petrol-Neodesha Project

With the acquisition of the Petrol-Neodesha and certain oil properties, we are currently providing ongoing revenue and cash from these properties. 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. Currently, we have been drilling about 3 wells per month. Given appropriate economics we plan to continue with that development rate.

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With the enhancements to gas gathering pipeline systems that we finalized late spring and early summer of 2005 we now have additional pipeline capacity to fully develop this 10,000 gross acre property. In fact we have drilled and completed 14 new production wells that were all 100% successes.

Coal Creek Project

On October 31, 2005, we entered into agreements with Laurus Master Fund, Ltd. Under the terms of the Laurus Funds agreements, $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 Secured Term Note (the “Note”) in the aggregate principal amount of $10,000,000 and a five-year warrant (the “Warrant”) to purchase 1,000,000 shares of our common stock at $2.00 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 3.25%, subject to a floor of 10% and a ceiling of 14% per annum.

In addition, Laurus Master Funds, in their sole discretion, may 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.

The net proceeds derived from this first Laurus Funds Financing Transaction have been utilized in the development of two areas within the Coal Creek project, specifically the Burlington area and the Waverly area. This will involve some 40 production wells, 3 salt water disposal wells and the installation of miles of gas gathering pipelines and processing systems within each of those production areas.

The entire Coal Creek development plan includes drilling and completing of some 540 wells and three gas gathering pipeline systems over a two to three year period. The anticipated costs of this full development plan is expected to be approximately $66,000,000 for which we expect to acquire a majority of funding through the $50,000,000 Laurus Master Fund Ltd credit facility. The pace of the development will obviously depend on the availability of the financing program and favorable market conditions.

The first $10,000,000 tranche is being used primarily to initiate Phase I with the drilling of gas production wells as well as the installation of a gas gathering pipeline system in two of the three areas, Burlington and Waverly. We also intend to fund portions of our field operations and development program from revenues obtained from sales of our CBM gas and oil production, outside lenders, and from proceeds of anticipated exercise of warrants and options. In addition, we may take on Joint Venture (JV) or Working Interest (WI) partners that will contribute to the capital costs of drilling and completion and then share in revenues derived from production. This economic strategy may allow us to realize the value in our own financial assets toward the growth of our leased acreage holdings, pursue the acquisition of strategic oil and gas producing properties or companies and generally expand our existing operations.

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In April 2006 we closed escrow on the second tranche of $5 million to support our drilling program on our Coal Creek Project.

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.

Liquidity and Capital Resources

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 $8.0 million 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. 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 six 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 next 333,333 shares. 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 April 4, 2006, Laurus has converted $2,283,822.52 of principal payments into 1,522,550 shares of our common stock and $779,351.74 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 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 million and a five-year warrant to purchase 200,000 shares of our common stock at $1.80 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 3.25%, 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 million Secured Term Note dated October 31, 2005 with Laurus.

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On April 7, 2006, the funds were released from Escrow. Net proceeds to the Company from the financing, after payment of fees and expenses to Laurus and its affiliates, were $4,806,687.50. The proceeds are being utilized by the Company for drilling activities on our Coal Creek Project.

Cash Flows. Since inception, we have financed cash flow requirements through debt financing and the issuance of common stock. 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.

Over the next twelve months we believe that our existing capital combined with cash flow from operations and funds from the October 31, 2005 Laurus Funds Financing Transaction, will be sufficient to sustain operations and planned expansion without additional financing through fiscal 2006.

We may incur operating losses over the next twelve months. Our lack of operating history 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.

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Field Development

Our original Operation Plan for field development 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. We believe that we have leased sufficient mineral acreage to move forward with our field development and with the proceeds of our recent $10 million financing we are proceeding with the next phase of our operations which is large field scale development of our Coal Creek Project.

During a two year exploration and development phase of our operational plan in the Coal Creek and Missouri projects, we drilled and tested a total of 23 wells. The results of these drilling and testing efforts have provided our geologists and engineers with data that support the quantitative determination concerning the gas content and commercially producible amounts of CBM or other types of more conventional natural gas. Eighteen of these exploratory/test wells are contained within our Coal Creek project in Coffey county, Kansas. Most are in proximity to an existing interstate gas pipeline. The total drilling depth for our Kansas project wells in Coal Creek is approximately 1,700 ft, while in Missouri that depth shallow to about 700 ft.

Kansas Geologic Society (KGS) joined us in our scientific effort designed to assess the gas reserves from our CBM exploratory/test wells in the Coal Creek Project. KGS took samples from coal beds found in our Coffey County wells. Their laboratory test results yielded similar gas content values to those obtained by our geologist, Mr. William Stoeckinger, that were derived from sampling 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 producing Prioject 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 $1,600 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 Reserve Report dated December 31, 2005 indicates Petrol has significant proven undeveloped gas reserves on its leases in the Coal Creek Project. After receiving the $10,000,00 tranche from Laurus Master Funds in November 2005 we immediately began the development of the Coal Creek Project with the intent of producing those reserves and increasing the Net Asset Value of that Project area.

Our Petrol-Neodesha project has room for another 50 to 100 wells 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 a several of new booster pumps and miles of larger diameter trunk lines that will accommodate production form all our new wells. Since the fall of 2005 we have drilled on average 3 new wells per month and have continued at that rate into first quarter of 2006. Finally, we instituted a well remediation program for some older producing wells that has resulted enhanced production.

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In general our field development plan is employed over all its projects and involves 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 and connected to our local gas gathering and water disposal pipelines during which an assessment will be made with regard to its de-water process and gas production.

When we identified a proposed drilling site, we as a licensed operator in the State of Kansas and Missouri, will be engaged in all aspects of well site operations. As the operator we will be responsible for permitting the well, which will include obtaining permission from the Kansas Oil and Gas commission or Missouri relative to spacing requirements and any other state and federal environmental clearances required at the time that the permitting process commences. Additionally, we will formulate and deliver 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 will be 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. We will be responsible for completing each successful well and connecting it to the most appropriate portion of our gas gathering system.

As the operator we will be the caretaker of the well once production has commenced. As the operator, we will be responsible for paying bills related to 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 has been sold, we anticipate that the purchaser thereof will carry out its own research with respect to ownership of that production and will send 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 will issue the checks to each interest owner in accordance with its appropriate interest. From that point forward, we as operator will be responsible for maintaining the well and the wellhead 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 CBM production wells we will 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 will be brought to bear on these new areas in Coal Creek or Missouri. 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 Enbridg e in our Coal Creek Project

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Presently, we are determining the costs of transporting our gas products to these existing interstate pipelines. The cost of installing a distribution infrastructure or local gathering system will vary 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, we anticipate that the total cost of installing a distribution infrastructure for a group of about 50-75 producing wells will be approximately $6,500 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 prices obtained for oil and gas are 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. We have entered into forward sales contracts for a portion of the gas and oil we presently produce. We do not have any delivery commitments for gas or oil from wells not currently drilled. However, due to the U.S. government’s recent push toward increased domestic production of energy sources, and 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, 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 eight contract personnel that support and operate our field operations. As drilling production activities increase, we intend to hire additional technical, operational and administrative personnel as appropriate. None of our employees are subject to any collective bargaining agreements; however, we have entered into employment agreements with Paul Branagan and Gary Bridwell. We expect a significant change in the number of full time employees over the next 12 months. However, at this time we are unable to quantify exactly how many. 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.

Our proposed personnel structure could be divided into three broad categories: management and professional, administrative, and project field personnel. As in most small companies, the divisions between these three categories are somewhat indistinct, as employees are engaged in various functions as projects and work loads demand.

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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, 2005:

	Year Ending December 31,
	2006	2007
Gas
Contract volume	732,200	180,000
Weighted-average price	$8.13	$9.17
Oil Contract volume	6,600	--
Weighted-average price	53.93	--
Fair value asset (liability)	$856,588	($67,955)

Critical Accounting Policies and Estimates

Our accounting estimates includes 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 receivables have been fully collectible since inception and we only have sales to a small base of customers so 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

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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 would be understated. 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. Gas price realizations ranged from a monthly low of approximately $5.02 per Mcf to a monthly high of approximately $14.03 per Mcf during the same period.

Since new well development is an ongoing program, 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.

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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 Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon his evaluation, Mr. Branagan concluded that our disclosure controls and procedures were not effective in timely alerting him to material information required to be included in our periodic SEC filings relating to our financial statement and other disclosures.  Our conclusions regarding the deficiencies were as follows:

Our controls relating to disclosure and related assertions in the financial statements, particularly in the area of accounting for a stock option issuance to a consultant was not adequate.

• We failed to account for the issuance of options to a consultant during the quarter ended March 31, 2006.

• We further found that while the controls over initiating and recording routine transactions were adequate, we had inadequate procedures to ensure equity transaction are recorded and processed in a timely manner. The finding of this weakness resulted in the need to amend the financial statements in this quarterly filing on Form 10-QSB/A. We believe that we have corrected this deficiency and will continue to carefully monitor the proper application of this control.

Other than the deficiencies and weaknesses described above, Mr. Branagan concluded that our disclosure controls and procedures are otherwise effective.

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.

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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 of our assets to repay the notes.

On October 28, 2004, we entered into an $8 million credit facility with Laurus Master Fund, Ltd. pursuant to a secured convertible term note and related agreements. On October 1, 2005, we entered into a $10 million credit facility with Laurus Master Fund, Ltd., pursuant to a secured note and related agreements. 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; 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.

There can be no assurance that we will satisfy all of the conditions of the agreements executed in the private placement with Laurus Funds.

Pursuant to the terms of certain agreements, we are subject to a condition subsequent to obtain an effective registration statement permitting the resale of common stock issued upon the exercise of the conversion rights of the purchaser and the exercise of the warrants by the purchaser on or before one hundred days. Although we believe that we will meet the deadline for obtaining an effective registration statement, there can be no assurance that such a statement will be declared effective within the time required. Failure to satisfy this condition subsequent would constitute a default. In connection with the transaction, we have granted to Laurus Funds a security interest in the assets purchased.

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.

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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. In some of the days 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.

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

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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 and development stage operations, 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.

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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.

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 to 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.

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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

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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.

At this stage of our business operations, even with our good faith efforts, potential investors have a possibility of losing their investment.

Because the nature of our business is expected to change as a result of shifts in the market price of oil and natural gas, competition, and the development of new and improved technology, management forecasts are not necessarily indicative of future operations and should not be relied upon as an indication of future performance.

While Management believes its estimates of projected occurrences and events are within the timetable of its business plan, our actual results may differ substantially from those that are currently anticipated.

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

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.

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 and expect to continue to have substantial capital expenditure and working capital needs. We believe that current cash on hand and the other sources of liquidity are only sufficient enough to fund our operations through fiscal 2006. 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.

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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.

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.

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We are highly dependent on Paul Branagan, our CEO, president and chairman. The loss of Mr. Branagan, whose knowledge, leadership and technical expertise upon which we rely, would harm our ability to execute our business plan.

Our success depends heavily upon the continued contributions of Paul Branagan, whose knowledge, leadership and technical expertise would be difficult to replace, and on our ability to retain and attract experienced engineers, geoscientists and other technical and professional staff. We have entered into an employment agreement with Mr. Branagan; however, maintain no key person insurance on Mr. Branagan. In addition, Mr. Branagan is an officer and director of other public companies, which may impact the amount of his time spent on our business matters. If we were to lose his services, our ability to execute our business plan would be harmed and we may be forced to cease operations until such time as we could hire a suitable replacement for Mr. Branagan.

We recently completed an acquisition of certain assets and we may acquire more assets or other businesses in the future.

We recently acquired certain assets owned by Savage Resources, LLC and Savage Pipeline, LLC for the purchase price of approximately $10 million, all of which was paid in cash. This is the first big acquisition for our Company and Management team. Our ability to successfully integrate the Savage acquisition into our existing operations is anticipated to depend on a number of factors.

We may consider acquisitions of other assets or other business. Any acquisition involves a number of risks that could fail to meet our expectations and adversely affect our profitability. For example:

• The acquired assets or business may not achieve expected results;

• We may incur substantial, unanticipated costs, delays or other operational or financial problems when integrating the acquired assets;

• We may not be able to retain key personnel of an acquired business;

• Our management’s attention may be diverted; or

• Our management may not be able to manage the acquired assets or combined entity effectively or to make acquisitions and grow our business internally at the same time.

If these problems arise we may not realize the expected benefits of an acquisition.

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:

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• 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.

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

The following table shows the conversions of principal and accrued interest made in the first quarter and subsequent by Laurus Master Fund Ltd. pursuant to the Convertible Term Note dated October 24, 2004.

CONVERSION DATE	PRINCIPAL AMOUNT	INTEREST AMOUNT	# OF SHARES FOR PRINCIPAL	# OF SHARES FOR INTEREST	DATE ISSUED
1/9/2006	$228,382.28	$54,287.55	152,255	36,192	1/9/2006
2/7/2006	$150,000.00	$0.00	100,000	0	2/8/2006
2/8/2006	$37,500.00	$0.00	25,000	0	2/9/2006
2/8/2006	$40,882.28	$52,989.21	27,255	35,326	2/14/2006
2/16/2006	$228,382.28	$0.00	152,255	0	2/17/2006
3/09/2006	$0.00	$46,250	0	30,834	3/09/2006
4/4/2006	$228,382.28	$49,771.35	152,255	33,181	4/04/2006
TOTAL	$913,529.12	$203,298.11	609,020	135,533

The shares issued for the conversion of principal were previously registered under our SB-2 declared effective on June 30, 2005.

The shares issued for the conversion of accrued interest were shares of our restricted common stock. 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) and Regulation D Rule 506. The shares were issued directly by us and did not involve a public offering or general solicitation. Laurus Funds is an “Accredited Investor” as defined in Rule 501 of Regulation D promulgated under the Securities Act. Laurus was afforded an opportunity for effective access to files and records of the Company that contained the relevant information needed to make its investment decision, including the financial statements and Exchange Act reports. We reasonably believe that Laurus immediately prior to issuing the shares, had such knowledge and experience in financial and business matters that they were capable of evaluating the merits and risks of their investment. Laurus had the opportunity to speak with our management on several occasions prior to its investment decision.

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During February 2006, we issued a total of 586,676 shares of our restricted common stock to the members of Petrol Oil, II LLC and Petrol Paola LLC in exchange for their respective membership interests pursuant to agreements entered into in December 2005. 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 recipients of the shares were afforded an opportunity for effective access to files and records of the Company that contained the relevant information needed to make their investment decision, including the Company's financial statements and 34 Act reports. We reasonably believe that the recipients, immediately prior to issuing the shares, had such knowledge and experience in its financial and business matters that they were capable of evaluating the merits mad risks of their investment. The recipients had the opportunity to speak with our president and directors on several occasions prior to their investment decision.

Pursuant to Joseph Blankenship’s Research Agreement dated February 9, 2004, he received options to purchase 25,000 shares for our common stock at $2.50 and options to purchase 25,000 shares of our common stock at $4.00 per share. On February 2, 2006, we extended the expiration date of his options from February 9, 2006 to February 9, 2008.

On February 8, 2006, we issued 7,595 shares of our restricted common stock to ECON Investor Relations, Inc., 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 were afforded an opportunity for effective access to files and records of the Company that contained the relevant information needed to make its investment decision, including the Company'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 mad risks of its investment. The recipient had the opportunity to speak with our president and directors on several occasions prior to its investment decision.

On February 13, 2006, GSSF Master Fund, LP exercised 50,000 warrants at a price of $1.50 per share. The 50,000 shares were issued on February 22, 2006 and were previously registered in our registration statement declared effective on June 30, 2005.

On February 13, 2006, Gryphon Master Fund, L.P. exercised 50,000 warrants at a price of $1.50 per share. The 50,000 shares were issued on February 22, 2006 and were previously registered in our registration statement declared effective on June 30, 2005.

On February 17, 2006, we issued 50,000 shares of our restricted common stock to Mike Draper as a finders fee for the Laurus Financing in October of 2005. 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 were afforded an opportunity for effective access to files and records of the Company that contained the relevant information needed to make its investment decision, including the Company'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 mad risks of its investment. The recipient had the opportunity to speak with our president and directors on several occasions prior to its investment decision.

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Pursuant to the Laurus Funds transaction entered into on March 31, 2006, we executed a $5 million secured term note and granted Laurus Funds a warrant to purchase 200,000 shares of its common stock at $1.80 per share. The Warrant is exercisable at any time or from time to time before 5:00 p.m., New York time, through the close of business March 30, 2011. The Company believes that the issuance and sale of the Warrant was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2) and Regulation D Rule 506. The warrant was issued directly by the Company and did not involve a public offering or general solicitation. Laurus Funds is an “Accredited Investor” as defined in Rule 501 of Regulation D promulgated under the Securities Act. Laurus Funds was afforded an opportunity for effective access to files and records of the Company that contained the relevant information needed to make its investment decision, including the financial statements and Exchange Act reports. The Company reasonably believes that Laurus Funds, immediately prior to issuing the warrants, had such knowledge and experience in financial and business matters that they were capable of evaluating the merits and risks of their investment. Laurus Funds had the opportunity to speak with the Company’s management on several occasions prior to its investment decision.

Subsequent Issuances

On April 13, 2006, we issued 11,512 shares of our restricted common stock to Edward Birk in exchange for 10% discount on the cost of certain invoices. 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 were afforded an opportunity for effective access to files and records of the Company that contained the relevant information needed to make its investment decision, including the Company'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 mad risks of its investment. The recipient had the opportunity to speak with our president and directors on several occasions prior to its investment decision.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

None.

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Item 6. Exhibits.

Exhibit Number	Description
2	Asset Purchase Agreement between Petrol Energy, Inc. and Euro Technology Outfitters, August 19, 2002 (Incorporated by reference to Exhibit (2) to Form SB-2 filed on January 22, 2003)
3i	Articles of Incorporation
	(a)         Certificate of Amendment of Articles of Incorporation of Euro Technology Outfitters, filed on August 20, 2002 (Incorporated by reference to Exhibit (3)(i)(a) to Form SB-2 filed on January 22, 2003)
	(b)         Articles of Incorporation for Euro Technology Outfitters, filed on March 3, 2000 (Incorporated by reference to Exhibit (3)(i)(b) to Form SB-2 filed on January 22, 2003)
3ii	Bylaws for Euro Technology Outfitters (Incorporated by reference to Exhibit (3)(ii) to Form SB-2 filed on January 22, 2003)
10.1	Amendment to Translation and Business Consulting agreement with Goran Blagojevic dated December 20, 2002 (Incorporated by reference to Exhibit 10.1 to Form SB-2 filed on January 22, 2003)
10.2	Service and Water Disposal Agreement dated November 15, 2002 (Incorporated by reference to Exhibit 10.2 to Form SB-2 filed on January 22, 2003)
10.3	Employment agreement with Paul Branagan dated December 19, 2002 (Incorporated by reference to Exhibit 10.3 to Form SB-2 filed on January 22, 2003)
10.4	Geologist/Technical Advisor Consulting Agreement with William Stoeckinger dated December 19, 2002 (Incorporated by reference to Exhibit 10.4 to Form SB-2 filed on January 22, 2003)
10.5	Land Services Consulting Agreement with Russell Frierson dated December 27, 2002 (Incorporated by reference to Exhibit 10.5 to Form SB-2 filed on January 22, 2003)
10.6	Land Services Consulting Agreement with Lawrence Kehoe dated December 27, 2002 (Incorporated by reference to Exhibit 10.6 to Form SB-2 filed on January 22, 2003)

10.7	Land Services Consulting Agreement with Cody Felton dated December 27, 2002 (Incorporated by reference to Exhibit 10.7 to Form SB-2 filed on January 22, 2003)
10.8	Waverly Kansas Office Lease dated January 21, 2003 (Incorporated by reference to Exhibit 10.8 to Form SB-2 filed on January 22, 2003)
10.9	2002 Master Stock Option Plan (Incorporated by reference to Exhibit 10.9 to Form SB-2 filed January 22, 2003)
10.10	Term Sheet of Compensation for Enutroff, dated 7/01/03 (Incorporated by reference to Exhibit 10.1 to Form 10-QSB filed on September 30, 2003)
10.11	Consultant Agreement of CSC Group LLC (Incorporated by reference to Exhibit 10.10 to Form 10-KSB filed on April 15, 2004)
10.12	Employment Agreement of David Polay (Incorporated by reference to Exhibit 10.11 to Form 10-KSB filed on April 15, 2004)
10.13	Addendum to Employment Agreement of Paul Branagan (Incorporated by reference to Exhibit 10.12 to Form 10-KSB filed on April 15, 2004)
10.14	Employment Agreement of Gary Bridwell (Incorporated by reference to Exhibit 10.13 to Form 10-KSB filed on April 15, 2004)
10.15	Letter Agreement with William D. Burke (Incorporated by reference to Exhibit 10.14 to Form 10-KSB filed on April 15, 2004)
10.16	Purchase and Sale Agreement with CBM Energy Inc. (Incorporated by reference to Exhibit 10.15 to Form 10-KSB filed on April 15, 2004)
10.17	Research Agreement with Joseph E. Blankenship (Incorporated by reference to Exhibit 10.16 to Form 10-KSB filed on April 15, 2004)
10.18	Research Agreement Scope of Work and Compensation (Incorporated by reference to Exhibit 10.17 to Form 10-KSB filed on April 15, 2004)

10.19	Business Partnership Term Sheet with John Haas, Mark Haas, and W.B. Mitchell (Incorporated by reference to Exhibit 10.18 to Form 10-KSB filed on April 15, 2004)
10.20	Addendum #2 Employment Agreement of Paul Branagan (Incorporated by reference to Exhibit 10.6 to Form 10-QSB filed on May 17, 2004)

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10.21	Securities Purchase Agreement for Laurus (Incorporated by reference to Exhibit 10.21 to Form SB-2 filed on February 7, 2005)
10.22	Registration Rights Agreement for Laurus (Incorporated by reference to Exhibit 10.22 to Form SB-2 filed on February 7, 2005)
10.23	Subscription and Registration Rights Agreement for Unit Offering (Incorporated by reference to Exhibit 10.23 to Form SB-2 filed on February 7, 2005)
10.24	Warrant Agreement for Unit Offering (Incorporated by reference to Exhibit 10.24 to Form SB-2 filed on February 7, 2005)
10.25	Amendment No. 1 to the Secured Convertible Term Note & Registration Rights Agreement with Laurus, dtd 1/28/05 (Incorporated by reference to Exhibit 10.25 to Form SB-2 filed on February 7, 2005)
10.26	Common Stock Purchase Warrant of Laurus, dated 01/28/05 (Incorporated by reference to Exhibit 10.26 to Form SB-2 filed on February 7, 2005)
10.27	Letter Amendment Agreement with Laurus, dated 04/28/05 (Incorporated by reference to Exhibit 10.27 to Form SB-2 filed on May 12, 2005)
10.28	Consulting Agreement with CEOcast, dated 08/7/04 (Incorporated by reference to Exhibit 10.28 to Form SB-2 filed on May 12, 2005)
10.29	Amendment No. 1 to October 2004 Securities Purchase Agreement (Incorporated by reference to Exhibit 10.29 to Form SB-2 filed on December 1, 2005)
10.30	Securities Purchase Agreement dated October 31, 2005 (Incorporated by reference to Exhibit 10.30 to Form SB-2 filed on December 1, 2005)
10.31	Secured Term Note dated October 31, 2005 (Incorporated by reference to Exhibit 10.31 to Form SB-2 filed on December 1, 2005)
10.32	Common Stock Purchase Warrant dated October 31, 2005 (Incorporated by reference to Exhibit 10.32 to Form SB-2 filed on December 1, 2005)
10.33	Registration Rights Agreement dated October 31, 2005 (Incorporated by reference to Exhibit 10.33 to Form SB-2 filed on December 1, 2005)

10.34	Amended and Restated Mortgage (Incorporated by reference to Exhibit 10.34 to Form SB-2 filed on December 1, 2005)
21	List of Subsidiaries of Petrol Oil and Gas, Inc.
31*	Certification of Paul Branagan pursuant to Section 302 of the Sarbanes-Oxley Act.
32*	Certification of Paul Branagan pursuant to Section 906 of the Sarbanes-Oxley Act.
99	Audit Committee Charter (Incorporated by reference to Exhibit 99 to Form 10-KSB filed on March 31, 2006)

_* Filed herewith

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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/ Paul Branagan                                                           

	Paul Branagan, Chief Executive Officer
(On behalf of the registrant and as
	principal accounting officer)

Date: July 11, 2006

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