Petrol Oil & Gas 10Q 2006 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 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 110^th Street, Suite 500
Overland Park, Kansas	66210
(Address of principal executive offices)	(Zip Code)

(913) 323-4925

(Registrant’s telephone number, including area code)

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 October 26, 2006 was 29,034,597 shares.

PART I -- FINANCIAL INFORMATION

Item 1. Financial Statements.

Petrol Oil and Gas, Inc.

Condensed Consolidated Balance Sheets

	September 30,		December 31,
	2006		2005
	Unaudited		Audited
Assets
Current assets:
Cash	$	8,090,149	$	8,435,203
Accounts receivable		1,009,608		613,814
Prepaid expenses		28,040		-
Total current assets		9,127,797		9,049,017

Fixed assets, net		4,198,636		2,444,903

Other assets:
Oil and gas properties using full cost accounting
Properties not subject to amortization		1,280,421		954,002
Properties subject to amortization		22,199,090		13,662,783
Capitalized loan costs, net		808,616		816,329
Deposits		1,932		-
Derivative asset		353,199		-
Total other assets		24,643,258		15,433,114

	$	37,969,691	$	26,927,034


Liabilities and Stockholders’ Equity

Current liabilities:
Accounts payable		272,219		1,374,938
Accrued liabilities		322,242		151,168
Short-term derivative liability		-		1,183,685
Current portion of long-term debt		11,671,451		2,101,111
Total current liabilities		12,265,912		4,810,902

Asset retirement obligation		858,797		749,618
Long-term derivative liability		-		512,931
Long-term debt, less current portion		16,021,723		12,375,007
		16,880,520		13,637,556

Commitments and contingencies		-		-

Stockholders’ equity:
Preferred stock, $0.001 par value, 10,000,000 shares authorized,
no shares issued and outstanding		-		-
Common stock, $0.001 par value, 100,000,000 shares authorized,
29,024,470 and 26,890,083 shares issued and outstanding at
September 30, 2006 and December 31, 2005, respectively		29,024		28,890
Shares purchased for services not issued, zero and 740,000 at
September 30, 2006 and December 31, 2005, respectively		-		740
Unamortized shares, warrants and options issued for services		(1,626,110)		(2,380,365)
Prepaid share-based compensation		(68,000)		-
Subscription receivable		-		(75,000)
Additional paid in capital		28,492,551		25,534,113
Other comprehensive income (loss)		353,199		(1,696,616)
Accumulated (deficit)		(18,357,405)		(12,931,186)
		8,823,259		8,478,576

	$	37,969,691	$	26,927,034

See notes to condensed consolidated financial statements.

Petrol Oil and Gas, Inc.

Condensed Consolidated Statement of Operations

(unaudited)

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Revenue
Oil and gas activities	$	1,947,729	$	1,493,770	$	4,988,661	$	4,489,872

Expenses:
Direct costs		556,365		941,418		1,711,719		2,653,270
Pipeline costs		267,809		-		651,731		-
General and administrative		398,373		795,764		1,769,788		1,416,115
Professional and consulting fees		207,251		253,247		1,480,137		1,807,881
Depreciation, depletion and amortization		1,005,939		314,899		1,939,619		897,003
Total expenses		2,435,737		2,305,328		7,552,994		6,774,269

Net operating (loss)		(488,008)		(811,558)		(2,564,333)		(2,284,397)

Other (expense):
Interest expense		(1,003,794)		(405,826)		(2,861,886)		(1,235,349)

Net (loss)	$	(1,491,802)	$	(1,217,384)	$	(5,426,219)	$	(3,519,746)

Weighted average number of common
shares outstanding-basic and fully diluted		29,010,350		25,656,528		28,665,768		25,196,538

Net (loss) per share-basic and fully diluted	$	(0.05)	$	(0.05)	$	(0.19)	$	(0.14)

See notes to condensed consolidated financial statements.

Petrol Oil and Gas, Inc.

Condensed Consolidated Statement of Cash Flows

(unaudited)

	Nine Months Ended
	September 30,
	2006		2005
Cash flows from operating activities
Net (loss)	$	(5,426,219)	$	(3,519,746)
Depreciation, depletion and amortization		1,939,619		897,003
Warrant accretion		938,294		745,026
Accretion of asset retirement obligation		52,779		37,194
Shares issued for interest		203,299		412,797
Shares, warrants and options issued for services		1,024,047		1,299,048
Adjustments to reconcile net (loss) to cash
used in operating activities:
Accounts receivable		(395,794)		(660,955)
Prepaid and other assets		(29,972)		(10,628)
Investments		-		15,778
Accounts payable		(1,102,719)		(274,510)
Accrued liabilities		280,253		587,647
Accrued liabilities – related party		-		(270,000)
Net cash used in operating activities		(2,516,413)		(741,346)

Cash flows from investing activities
Purchase of fixed assets		(1,932,542)		(130,059)
Additions to oil and gas properties		(9,599,771)		(1,199,229)
Purchase of oil and gas leases		(326,209)		-
Release of restricted cash		-		852,346
Net cash used in investing activities		(11,858,522)		(476,942)

Cash flows from financing activities
Proceeds from loans payable		15,000,000		-
Payments on loans payable		(1,211,994)		(462,952)
Proceeds from exercising of warrants		241,875		300,100
Net cash provided (used) in financing activities		14,029,881		(162,852)

Net (decrease) in cash		(345,054)		(1,381,140)
Cash – beginning		8,435,203		1,792,885
Cash – ending	$	8,090,149	$	411,745

Supplemental disclosures:
Interest paid	$	1,624,754	$	65,710
Income taxes paid	$	-	$	-

Non-cash transactions:
Stock issued for oil and gas properties	$	615,998	$	-
Unamortized shares, warrants and options issued for services		68,000		40,200
Shares issued for debt conversion		963,301		297,833
Shares, warrants and options issued for services		1,024,047		1,189,490
Asset retirement obligation		54,600		206,500

See notes to condensed consolidated financial statements.

Petrol Oil and Gas, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1 - Basis of Presentation

The unaudited condensed financial statements have been prepared in accordance with United States generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and reflect all adjustments which, in the opinion of management, are necessary for a fair presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim period are not necessarily indicative of the results to be expected for a full year. Certain amounts in the prior year statements have been reclassified to conform to the current year presentations. These statements should be read in conjunction with the financial statements and footnotes thereto included in the Form 10-KSB for the year ended December 31, 2005.

Note 2 - Stock Transactions and Consulting Agreements

Common stock

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 152,255 shares of its common stock to Laurus.

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

On February 8, 2006, the Company 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, the Company 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.

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 April 4, 2006, Laurus Master Fund, Ltd. converted $49,772 of accrued interest due under the Convertible Term Note. Pursuant to the conversion rate of $1.50 per share the Company issued 33,181 shares of its common stock to Laurus.

On April 5, 2006, Laurus Master Fund, Ltd. converted $228,383 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.

Petrol Oil and Gas, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

On April 13, 2006, the Company issued 11,512 previously authorized shares of its common stock.

On May 9, 2006, the Company issued 368,861 shares of its common stock for the purchase of working interests in producing wells.

On June 27, 2006, the Company issued 15,190 shares of its common stock for investor relation services, the Company recorded consulting expense in the amount of $36,000, the fair value of the underlying shares.

On September 26, 2006, the Company issued 60,000 shares of its common stock pursuant to its one year agreement for investor relations services. The Company recorded consulting expense in the amount of $13,600 and prepaid share-based compensation of $68,000, the fair value of the underlying shares.

Warrants and options

On January 1, 2006, the Company entered into a one year agreement with R. J. Falkner whereby the Company 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 September 30, 2006, the Company expensed $78,003 as consulting fees.

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

On April 1, 2006, the Company granted Laurus Master Fund 200,000 warrants at a strike price of $1.80 per share for a five-year period in connection with the new note. The value of the warrants was $265,015. The value will be accreted to interest expense over the estimated term of the loan.

On April 28, 2006, the Company issued 105,000 shares of its common stock for the exercise of warrants in exchange for cash totaling $91,875.

On May 31, 2006, the Company granted Laurus Master Fund 400,000 warrants at a strike price of $1.65 per share for a five-year period in connection with the new note. The value of the warrants was $396,763. The value will be accreted to interest expense over the estimated term of the loan.

On September 15, 2006, the Company granted CSC Group 25,000 options at a strike price of $1.75 exercisable for a period of five years. The value of the option was $10,338 and was recorded as consulting expense.

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	135,000	1.76	600,000	1.70
Cancelled	-	-	3,950,000	1.47
Exercised	-	-	205,000	1.18
Outstanding 09/30/06	2,910,000	$1.68	14,936,666	$1.44

Note 3 - Asset Retirement Obligation

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

Petrol Oil and Gas, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

		September 30, 2006
Asset retirement obligation, 1/1/06		$ 749,618
Liabilities incurred		56,400
Liabilities settled		--
Accretion of expense		52,779
Asset retirement obligations, 9-30-06		$ 858,797

Note 4 - Long-Term Debt

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. The proceeds will be utilized by the Company for drilling activities on the Company’s Coal Creek Project.

On May 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 $10,000,000 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 $10 million and a five-year warrant (the “Warrant”) to purchase 400,000 shares of the Company’s common stock at $1.65 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. The proceeds will be utilized by the Company for drilling activities on the Company’s Coal Creek Project.

Long-term debt consists of the following:

	September 30, 2006
Total notes payable	$ 29,114,302
Less unamortized cost of warrants	(1,434,455)

	27,679,847
Less current portion	(11,671,451)
Total long-term debt	$ 16,008,396

During the nine months ended September 30, 2006, the accretion of the warrants that was included in interest expense totaled $355,134.

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 September 30, 2006, we had contracts covering approximately 60,000 mmbtu per month for the period of July l 2006 to March

Petrol Oil and Gas, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

2007 at an average price of $8.73 per mmbtu. We also had contracts for oil production for July, 2006 covering 660 barrels per month at an average price of $55.80. The contract terminated effective August 1, 2006.

Note 6 - Subsequent Events

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

On October 26, 2006, the Company issued 10,127 shares of its par value common stock as payment for investor relation services. The fair value of the services is $24,000.

FORWARD-LOOKING STATEMENTS

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

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

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

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 Part II, Item 1A. Risk Factors, in this document.

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

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

OVERVIEW AND OUTLOOK

We are an oil and gas exploration, development and production company. Our properties are located in the Cherokee 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.

We have consolidated 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 markets 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:

Coal Creek Project - current development of about 92,000 gross acres (73,000 net acres) with 49 production wells, 5 salt water disposal wells and gas gathering infrastructure.

Petrol-Neodesha Project - 10,000 gross acre (8,000 net acres) with 101 wells producing approximately 2.86 Million cubic feet of gas a day (MMcfd)

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.

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

Oil Field Projects – 10,000 gross acres.

Coal Creek Project

The Coal Creek Project, centered in Coffey County, Kansas, includes leases covering about 92,000 gross acres. In October 2005 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 received in November 2005. In March 2006 we received the second installment of $5,000,000 and in May of 2006 we received the third installment of $10,000,000.

The Coal Creek development plan is based upon drilling and completing some 540 wells over a two to three year period along with three gas gathering pipelines and gas processing systems over a two to three year period. To better manage the development of this large acreage position and take advantage of the three interstate pipeline that cross our leases we divided the project into three fully self contained areas:

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.

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

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

The full development plan is expected to be executed in multiple phases. The initial phases involve emplacing the basic gas gathering pipeline infra-structures, developing about 180 new CBM gas production wells and multiple SWD wells. Later phases include finalizing the gas gathering pipeline and developing 360 more CBM gas production 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.

We began the first phase of our full scale development in the Coal Creek project with the drilling and completion of 24 production wells and 2 salt water disposal (SWD) wells in the Burlington area of Coal Creek. Completion of Phase 1 in Burlington occurred in late March 2006 when our gas gathering pipeline connections were made between the production wells and our compressor station. On April 4, 2006, our initial Burlington gas sales commenced through the Enbridge Interstate pipeline. Good natural fracture permeability in these gas bearing coal intervals is supported by early high water production rates.

The second area being developed in Coal Creek is the Waverly area. Phase I development in the Waverly area began during the first quarter of 2006 and included drilling and completing 19 CBM production wells and 1 SWD well. By mid June, our new Waverly gas gathering pipeline system was integrated between all 19 production wells and our gas compressor station. For months, our field operations worked diligently with Enbridge Pipeline to emplace a second tap and gas sales monitoring system on the Enbridge interstate pipeline, which ultimately transports our gas from these new Waverly area CBM wells to market for sale. All 19 Waverly production wells are in various stages of de-watering, and as in Burlington, permeability of the coal beds is manifested by early water production and gas rates are modest but continuously increasing as the fracture system de-waters.

As part of the next phase of development in Coal Creek 6 CBM production wells and 2 SWD wells were emplaced. The location of these new production wells was designed to support de-watering in the immediate area around the original Phase I production wells and to provide technical insight into the de-watering process.

On September 28, 2006, we announced that we received approval from the Kansas Corporation Commission to operate two new salt water disposal wells on our Coal Creek Project.

Petrol-Neodesha Project

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 104 CBM wells. On average 97 of those CBM producing wells produce approximately 2.86 MMcfd. 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.

In the spring and summer of 2005 we implemented Phase I of our Neodesha development plan that involved expanding the production capacity of our existing gas gathering pipeline system and drilling several new production wells. 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. We also incorporated a new gas processing unit into our Neodesha pipeline system to support growing gas sales and enhance gas quality.

The second element of the Phase I development plan involved drilling a series of new multi-zone CBM production wells. Since January 1, 2006, Petrol has completed six new multi-zone production wells on its Petrol-Neodesha (“Neodesha”) properties, with a 100% success rate. Currently these six new wells are producing approximately 240 thousand cubic feet of gas per day (Mcfd). Overall Petrol-Neodesha production has increased from 2,598 Mcfd on January 1, 2006 to a current rate of 2,860 Mcfd. We drilled an additional five more successful multi-zone wells that are awaiting completion. Drill stem tests on these five wells ranged from a low of 40 Mcfd to a high of 415 Mcfd. Petrol plans to drill and complete additional Neodesha wells during the balance of 2006. All the new wells will be completed and connected to the newly enhanced gas gathering pipeline system.

The current phase of our Neodesha development plans involves implementing a program employing advanced stimulation methodologies and re-completion techniques. The program is designed to improve our overall understanding of the effectiveness of multi-zone stimulations and their ability to enhance production and reduce stimulation costs. Petrol is actively involved in executing the data acquisition portion of this plan. Petrol has employed outside consultants with expertise in fracture stimulation of un-conventional reservoirs such as CBM to support our efforts in this technical program.

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 for the Three Months Ended September 30, 2006 and 2005.

The following table summarizes selected items from the statement of operations at September 30, 2006 compared to September 30, 2005.

INCOME:

	Three Months Ended September 30,
	2006	2005	Increase / (Decrease)
	Amount	Amount	$	%
Revenues	$ 1,947,729	$ 1,493,770	453,959	30%

Revenues

Revenues for the three months ended September 30, 2006 were $1,947,729 compared to revenues of $1,493,770 in the three months ended September 30, 2005. This resulted in an increase of $453,959 or 30%, from the same period one year ago. The increase in revenues is a result of higher hedged prices of our gas and higher gas prices in general.

EXPENSES:

	Three Months Ended September 30,
	2006	2005	Increase / (Decrease)
	Amount	Amount	$	%
Expenses:
Direct Costs	$ 556,365	$ 941,418	$ (385,053)	(41%)
Pipeline costs	267,809	-	267,809	-
General and administrative	398,373	795,764	(397,391)	(50%)
Professional and consulting Fees	207,251	253,247	(45,996)	(18%)
Depreciation, depletion and amortization	1,005,939	314,899	691,040	219%
Total expenses	2,435,737	2,305,328	130,409	6%

Net operating (loss)	(488,008)	(811,558)	(323,550)	(40%)

Other income (expense):
Interest expense	(1,003,794)	(405,826)	597,968	147%

Net loss	$ (1,491,802)	$ (1,217,384)	$ 274,418	23%

Direct Costs

Direct costs are the costs associated with operating producing wells, and transporting the oil and natural gas to the market for sale. Direct cost for the three months ended September 30, 2006 was $556,365, a decrease of $385,053, or 41%, from $941,418 for the three months ended September 30, 2005. The decrease over the prior period is directly attributable to our reduction in costs related to work-overs, repairs and modification to the Neodesha wells and pipeline system that we had previously experienced during the same period in the previous year. We do not anticipate maintenance and work-over costs to that extent in the future and our current direct operating costs are more indicative of our overall production costs.

Pipeline Costs

Pipeline costs were $267,809 for the three months ended September 30, 2006. We did not incur pipeline costs for the three months ended September 30, 2005.

General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2006 were $398,373, a decrease of $397,391, or 50%, from $795,764 for the three months ended September 30, 2005. The decrease in general and administrative expenses is attributable to streamlining and reduction of expenses.

Professional and Consulting Fees

Professional and consulting fees for the three months ended September 30, 2006 was $207,251, a decrease of $45,996, or 18%, from $253,247 for the three months ended September 30, 2005. The decrease in professional and consulting fees in the current period was a result of decreased investor relations fees.

Depreciation, Depletion, and Amortization Expense

Depreciation, depletion, and amortization expense for the three months ended September 30, 2006 was $1,005,939, an increase of $691,040, or 219%, from $314,899 for the three months ended September 30, 2005. The increase in depreciation, depletion and amortization expense was a result of increased depletion on each unit of production due to our increase in capital expenditures and a slight decline in reserves.

Net Operating (Loss)

The net operating loss for the three months ended September 30, 2006 was $488,008, versus a net operating loss of $811,558 for the three months ended September 30, 2005, a change in net loss of $323,550 or 40%. The decrease in net operating loss for the third quarter of 2006 was due to our overall decrease in lifting and operating costs associated with our production.

Other Income (Expense)

Interest expense

Interest expense for the three months ended September 30, 2006 was $1,003,794, an increase of $597,968, or 147%, from $405,826 for the three months ended September 30, 2005. The increase in interest expense is the result of the increased amount of debt financing received from Laurus Funds, including $355,135 attributable to the accretion of warrants issued to Laurus.

Net Loss

Our net loss for the three months ended September 30, 2006 was $1,491,802, an increase of $274,418, or 23%, from $1,217,384 for the three months ended September 30, 2005. The increase in net loss is the net result of increased interest expense and operating expense partially offset by increased revenues.

Results of Operations for the Nine Months Ended September 30, 2006 and 2005.

The following table summarizes selected items from the statement of operations at September 30, 2006 compared to September 30, 2005.

INCOME:

	Nine Months Ended September 30,
	2006	2005	Increase / (Decrease)
	Amount	Amount	$	%
Revenues	$ 4,988,661	$ 4,489,872	$ 498,789	11%

Revenues

Revenues for the nine months ended September 30, 2006 were $4,988,661 compared to revenues of $4,489,872 in the nine months ended September 30, 2005. This resulted in an increase of $498,789 or 11%, from the same period one year ago. The increase in revenues is a result of production from the Neodesha area.

EXPENSES:

	Nine Months Ended September 30,
	2006	2005	Increase / (Decrease)
	Amount	Amount	$	%
Expenses:
Direct costs	$1,711,719	$ 2,653,270	$(941,551)	(35%)
Pipeline costs	651,731	-	651,731	-
General and administrative	1,769,788	1,416,115	353,673	25%
Professional and consulting Fees	1,480,137	1,807,881	(327,744)	(18)%
Depreciation, depletion and Amortization	1,939,619	897,003	1,042,616	116%
Total expenses	7,552,994	6,774,269	778,725	11%

Net operating (loss)	(2,564,333)	(2,284,397)	279,936	12%

Other income (expense):
Interest expense	(2,861,886)	(1,235,349)	1,626,537	132%

Net (loss)	$(5,426,219)	$(3,519,746)	$ 1,906,473	54%

Direct Costs

Direct costs are the costs associated with operating producing wells, and transporting the oil and natural gas to the market for sale. Direct cost for the nine months ended September 30, 2006 was $1,711,719, a decrease of $941,551, or 35%, from $2,653,270 for the nine months

ended September 30, 2005. The decrease in direct costs is directly attributable to a reduction in costs related to work-overs, repairs and modification to the Neodesha wells and pipeline system that we had previously experienced during the previous year. We do not anticipate maintenance and work-over costs to that extent in the future and our current direct operating costs are more indicative of our overall production costs.

Pipeline Costs

Pipeline costs were $651,731 for the nine months ended September 30, 2006. We did not incur pipeline costs for the nine months ended September 30, 2005.

General and Administrative Expenses

General and administrative expenses for the nine months ended September 30, 2006 was $1,769,788, an increase of $353,673, or 25%, from $1,416,115 for the nine months ended September 30, 2005. The increase in general and administrative expenses is attributable to expenses associated with additional staff and expenses related thereto as the result of our growth in operations, especially the extensive development of our new Coal Creek project areas. Additionally, we experienced non re-occurring marketing expenses with the opening of our Coal Creek pipeline.

Professional and Consulting Fees

Professional and consulting fees for the nine months ended September 30, 2006 was $1,480,137, a decrease of $327,744, or 18%, from $1,807,881 for the nine months ended September 30, 2005. The decrease in professional and consulting fees, in the current period was a result of decreased legal and consulting fees previously incurred as a result of the requirements of our loan agreement with Laurus Master Fund.

Depreciation, Depletion, and Amortization Expense

Depreciation, depletion, and amortization expense for the nine months ended September 30, 2006 was $1,939,619, an increase of $1,042,616, or 116%, from $897,003 for the nine months ended September 30, 2005. The increase in depreciation, depletion and amortization expense was a result of an increase in depletion. As our production has increased, our remaining reserves have declined slightly, our depletion per unit of production has increased as expected.

Net Operating (Loss)

The net operating loss for the nine months ended September 30, 2006 was $2,564,333, versus a net operating loss of $2,284,397 for the nine months ended September 30, 2005, an increase in net loss of $279,936 or 12%. The increase in net operating loss for the nine months of 2006 was the result of increases in expenses partially offset by increase in revenue.

Other Income (Expense)

Interest Expense

Interest Expense for the nine months ended September 30, 2006 was $2,861,886, an increase of $1,626,537, or 132%, from $1,235,349 for the nine months ended September 30, 2005. The increase in interest expense is the result of our increased debt financing activities with Laurus Funds, including $938,291 attributable to the accretion of warrants issued to Laurus.

Net Loss

Our net loss for the nine months ended September 30, 2006 was $5,426,219, an increase of $1,906,473, or 54%, from $3,519,746 for the nine months ended September 30, 2005. The increase in net loss is primarily the result of increased interest expense associated with the new Laurus financing agreements for the development of infrastructure associated with our Coal Creek project.

Analysis and Discussion of Cash Flow

In the nine months ended September 30, 2006 our cash position decreased by $345,054. Our operating activities utilized $2,516,413 of cash mainly from operating expenses we incurred. We also used $11,858,522 of our cash for the capitalized costs of the pipeline, the capitalized cost of drilling more wells and for the acquisition and renewal of oil and gas leases. We repaid $1,211,994 on our notes.

Operation Plan

During the remainder of this year and into 2007 we plan to continue to focus our efforts on increasing production, and enhancing our Net Asset Value. We expect to achieve this through the:

•

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

•

the sustained development and production of CBM and other natural gases on our existing properties at the Petrol-Neodesha Project,

•

pursuing strategic acquisitions of producing properties; and

•

creating value by furthering our business plan.

Coal Creek Project

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

The net proceeds derived from the first Laurus Master Funds Financing transaction were used in the development of two areas within the Coal Creek project, specifically the Burlington area and the Waverly area. This first round of additional financing allowed us to emplace 43 production wells, 3 salt water disposal wells and install miles of gas gathering pipelines, salt water disposal lines, complex compressor stations and processing systems within those production areas.

Petrol received an additional $15,000,000 from its Laurus Credit facility during the spring of 2006. A portion of these additional funds were used to finalize the completion of some of the original Phase I wells, drilled 6 new CBM wells and 2 new salt water disposal wells, and continuing the integration of the gas gathering and water disposal system pipelines. In addition to the drilling process Petrol undertook a comprehensive testing program to identify, quantify and rank the most productive water producing intervals. The Coal Creek Project includes 49 producing wells and 5 salt water disposal wells. Currently, 46 of the 49 producing wells are connected to the gas gathering system while 3 are waiting to be fracture stimulated. The 5 salt water disposal wells are all active with the last 2 being approved by the Kansas Corporation Commission for injection the last week of September 2006.

The entire Coal Creek development plan includes drilling and completing about 540 production wells along with three gas gathering pipeline and gas processing 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.

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

Petrol-Neodesha Project

Petrol-Neodesha and our oil properties currently provide ongoing revenue and cash from sales of oil and gas. As we expand development and operational activities, we will weigh the pace of further drilling and development against the availability of internal and external funding. Currently, we have been drilling about 2 wells on average per month. Given appropriate economics we plan to continue with that development rate.

With the enhancements to gas gathering pipeline systems that Petrol finalized late spring and early summer of 2005 we now have additional pipeline capacity to fully develop this 10,000 gross acre property. During 2006 we have added a total of 15 new production wells to the 14 new production wells we drilled and completed in 2005. All 29 new production wells were 100% successes.

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

Liquidity and Capital Resources

The following table summarizes total assets, accumulated deficit, stockholders’ equity and working capital at September 30, 2006 compared to December 31, 2005.

	September 30, 2006	December 31, 2005	Increase / (Decrease)
	September 30, 2006	December 31, 2005	$	%

Current Assets	$ 9,127,797	$ 9,049,017	$ 78,780	1%

Current Liabilities	$ 12,265,912	$ 4,810,902	$ 7,455,010	155%

Working Capital (deficit)	$(3,138,115)	$ 4,238,115	$(7,376,230)	(174%)

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

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

As of September 30, 2006, Laurus has converted $2,283,823 of principal payments into 1,522,550 shares of our common stock and $779,352 of accrued interest into 519,568 shares of our common stock (2,042,118 shares in total). The conversion of principal and accrued interest allowed us additional cash to use in our operations.

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

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

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

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

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

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

Satisfaction of our cash obligations for the next 12 months.

A critical component of our operating plan impacting our continued existence is to efficiently manage the production from our Petrol-Neodesha Development and successfully develop our Coal Creek Project. Our ability to obtain additional capital through additional equity and/or debt financing, and Joint Venture or Working Interest partnerships will also be important to our expansion plans. In the event we experience any significant problems assimilating acquired assets into our operations or cannot obtain the necessary capital to pursue our strategic plan, we may have to reduce the growth of our operations. This may materially impact our ability to increase revenue and continue our growth.

Over the next twelve months we believe that our existing capital combined with cash flow from operations and funds from the Laurus Funds Financing Transactions, will be sufficient to sustain operations and planned expansion without additional financing through the second quarter of fiscal 2007.

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

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

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

Field Development

Our original Operation Plan for field development 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 financing with Laurus we are proceeding with the next phase of our operations which is large field scale development of our Coal Creek Project.

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

Coal Creek

Our operational plan called for an exploration and development phase involving the drilling and testing of 23 wells in the Kansas Coal Creek project and our Missouri project. Data and analysis acquired from these initial test wells provided our geologists and engineers with information that supported the quantitative determination concerning the gas content, reserve estimates and potential to produce commercial rates of CBM and other types of more conventional natural gas. Eighteen of these exploratory/test wells were located within our Coal Creek project in Coffey county, Kansas while the remaining 5 test wells are located in Missouri. By design most of these wells were located in proximity to an existing interstate gas pipeline. The total drilling depth for our Kansas project wells in Coal Creek was approximately 1,700 ft, while in Missouri that depth shallow to about 700 ft.

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

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

Our Reserve Report dated December 31, 2005 indicates we have significant proven undeveloped gas reserves on our leases in the Coal Creek Project to warrant development. After receiving the $10,000,000 installment from Laurus Master Funds in November 2005 we immediately began the development of the Coal Creek Project with the intent of producing those reserves, increasing revenues and enhancing the Net Asset Value of that Project area.

Presently the Coal Creek project has 49 production wells and 5 SWD wells with 31 of those production wells and 3 SWD wells located in the Burlington area and 18 of those production wells and 2 SWD well located in the Waverly area. Each area has its own gas gathering pipelines, water disposal lines, compressors and gas processing equipment to make connections with the Enbridge interstate pipeline.

Early water production from these Coal Creek producing intervals was found to be considerably higher than those found in the more mature production intervals of our Neodesha wells. Further, as many as 10-12 coal beds and shales were completed in the Coal Creek project wells compared to 2-3 coal beds normally completed in the Neodesha wells thus compounding the comparison between the two areas. During the past several months Petrol has been involved in a series of field tests in Coal Creek designed to isolate specific producing intervals, quantify water production and then embark on a strategy to reduce water production from the highest producing intervals. Results to date are encouraging with two test wells having the same high water rate interval shut off by cementing the perforations. Water production was cut in half which should allow the remaining 9-11 intervals to begin a more normal de-watering process.

In addition the strategy described above to shut off high rate water production intervals and the new additional salt water disposals wells should provide sufficient capacity to allow all our CBM wells to produce water at much higher rates. Both processes are of course designed to enhance and expedite the de-watering of the coal beds which should then promote gas production.

Petrol-Neodesha

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 several new booster pumps and miles of larger diameter trunk lines that will accommodate production for all our new wells. Since January 1, 2006, we have completed six new multi-zone production wells on our Petrol-Neodesha properties, with a 100% success rate. We drilled an additional nine successful multi-zone wells that are currently in various stages of completion in 2006. All these new wells will be completed and connected to the newly enhanced gas gathering pipeline system.

The next phase of our Neodesha development plan involves implementing a program employing advanced stimulation methodologies and re-completion techniques. The program is designed to improve our overall understanding of the effectiveness of multi-zone stimulations and their ability to enhance production and reduce stimulation costs. We are actively involved in executing the data acquisition portion of this plan.

We intend to continue seeking acquisition opportunities which compliment our current production area. Based on our current field production levels, we plan to aggressively develop Petrol-Neodesha.

General Operations

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

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

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

Along with the drilling and completion of our production wells our subsidiary pipeline companies formulate, design and install a gas gathering and compression system to transport the gas from wellhead to the high pressure interstate pipeline tap and sales market. Our experience in Petrol-Neodesha is being brought to bear on our new development area in Coal Creek and eventually to 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 Enbridge in our Coal Creek Project

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

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

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

Significant changes in the number of employees.

We currently have eight full time employees and two part time employee 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 our CEO and our onsite operations supervisor. We do not anticipate a significant change in the number of full time employees over the next 12 months. We intend to use the services of independent consultants and contractors to perform various professional services, particularly in the area of land services, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain general and administrative expenses.

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.

Consultant

On August 7, 2006, we renewed our consulting agreement with CEOcast, Inc., wherein CEOcast agreed to provide us with investor relations services. The term of the agreement is for one year. We agreed to compensate CEOcast $7,500 upon signing the agreement and 60,000 shares of our common stock. In addition, we will pay CEOcast $7,500 on or before the 7^th day of each month during the term of the agreement. The 60,000 shares of common stock were issued to CEOcast on September 26, 2006.

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)

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

Critical Accounting Policies and Estimates

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

Effects of Inflation and Pricing

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

Item 3. Quantitative and Qualitative Disclosure About Market Risk.

Commodity Price Risk

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

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.

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 our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based on the evaluation, which disclosed no significant deficiencies or material weaknesses, Mr. Branagan, our Chief Executive Officer and Principal Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting him to material information required to be included in our periodic SEC filings.

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

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

PART II--OTHER INFORMATION

Item 1.

Legal Proceedings.

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

Item 1A. Risk Factors.

Risks Associated with Laurus Funds Financing

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

On October 28, 2004, we entered into an $8,000,000 credit facility with Laurus Master Fund, Ltd. pursuant to a secured convertible term note and related agreements. On October 31, 2005, we entered into a $50 million credit facility with Laurus Master Fund, Ltd., pursuant to a secured note and related agreements whereby we received an initial $10,000,000. On March 31, 2006, we entered into agreements with Laurus Master Fund, Ltd. to draw down an additional $5,000,000 under the credit facility provided by Laurus on October 31, 2005. On May 31, 2006, we entered into agreements with Laurus Master Fund, Ltd. to draw down an additional $10,000,000 under the credit facility provided by Laurus on October 31, 2005. Subject to certain grace periods, the notes and agreements provide for the following events of default (among others):

•

Failure to pay interest and principal when due;

•

An uncured breach by us of any material covenant, term or condition in any of the notes or related agreements;

•

A breach by us of any material representation or warranty made in any of the notes or in any related agreement;

•

Any money judgment or similar final process is filed against us for more than $50,000;

•

Any form of bankruptcy or insolvency proceeding is instituted by or against us; and

•

Suspension of our common stock from our principal trading market for five consecutive days or five days during any ten consecutive days.

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

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

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

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

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

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

Risks Associated with Oil and Gas Operations

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

Developing and exploring for natural gas and oil involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. Any success that we may have with these wells or any future drilling operations will most likely not be indicative of our current or future drilling success rate, particularly, because we intend to emphasize on exploratory drilling. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

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

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

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

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

(

worldwide or regional demand for energy, which is affected by economic conditions;

•

the domestic and foreign supply of natural gas and oil;

•

weather conditions;

•

domestic and foreign governmental regulations;

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political conditions in natural gas and oil producing regions;

(

the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels; and

•

the price and availability of other fuels.

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

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

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

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.

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

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fires;

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explosions;

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blow-outs and surface cratering;

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uncontrollable flows of oil, natural gas, and formation water;

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natural disasters, such as hurricanes and other adverse weather conditions;

•

pipe, cement, or pipeline failures;

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casing collapses;

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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:

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injury or loss of life;

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severe damage to and destruction of property, natural resources and equipment;

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pollution and other environmental damage;

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clean-up responsibilities;

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regulatory investigation and penalties;

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suspension of our operations; and

•

repairs to resume operations.

Because we intend to use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.

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

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

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

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 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;

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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;

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operation of wells and reports concerning operations; and

•

taxation.

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

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

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

Risks Associated with Our Business

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

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

If low natural gas and oil prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues or cash flows from operations to decrease, we may be limited in our ability to spend the capital necessary to complete our development, production

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

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

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. 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.

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

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

•

Deliver to the customer, and obtain a written receipt for, a disclosure document;

•

Disclose certain price information about the stock;

•

Disclose the amount of compensation received by the broker-dealer or any associated person of the broker-dealer;

•

Send monthly statements to customers with market and price information about the penny stock; and

•

In some circumstances, approve the purchaser’s account under certain standards and deliver written statements to the customer with information specified in the rules.

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

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

The market for our common stock may experience extreme price and volume fluctuations, which may be unrelated or disproportionate to our operating performance or prospects. In the past, securities class action litigation has often been brought against companies following periods of volatility in the market prices of their securities. We may be the target of similar litigation in the future. Securities litigation could result in substantial costs and divert our management’s attention and resources, which could have a negative effect on our business, operating results and financial condition.

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

On September 15, 2006, we granted 25,000 options to Steve Cochennet, President of CSC Group, as partial payment for his consulting services during the months of July and August. The 25,000 options are exercisable for five years at a price of $1.75 per share. We believe that the grant of the options 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 options 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 Company’s financial statements and 34 Act reports. We reasonably believe that the recipient, immediately prior to granting the options, 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 September 26, 2006, we issued 60,000 shares of common stock to CEOcast, Inc., pursuant to its consulting agreement dated August 7, 2006. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2). The recipient of the shares was afforded an opportunity for effective access to files and records of 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.

Subsequent Issuances

On October 26, 2006, we issued 10,127 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

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 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.

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)
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)
10.35	Securities Purchase Agreement dated March 31, 2006 (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on April 11, 2006)
10.36	Secured Term Note dated March 31, 2006 (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on April 11, 2006)
10.37	Amended and Restated Secured Term Note (Incorporated by reference to Exhibit 10.3 to Form 8-K filed on April 11, 2006)
10.38	Common Stock Purchase Warrant dated March 31, 2006 (Incorporated by reference to Exhibit 10.4 to Form 8-K filed on April 11, 2006)
10.39	Registration Rights Agreement dated March 31, 2006 (Incorporated by reference to Exhibit 10.5 to Form 8-K filed on April 11, 2006)
10.40	Amended and Restated Mortgage (Incorporated by reference to Exhibit 10.6 to Form 8-K filed on April 11, 2006)

10.41	Securities Purchase Agreement dated May 31, 2006 (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on June 15, 2006)
10.42	Secured Term Note dated May 31, 2006 (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on June 15, 2006)
10.43	Amended and Restated Secured Term Note effective March 31, 2006 (Incorporated by reference to Exhibit 10.3 to Form 8-K filed on June 15, 2006)
10.44	Amended and Restated Secured Term Note effective October 31, 2005 (Incorporated by reference to Exhibit 10.4 to Form 8-K filed on June 15, 2006)
10.45	Common Stock Purchase Warrant dated May 31, 2006 (Incorporated by reference to Exhibit 10.5 to Form 8-K filed on June 15, 2006)
10.46	Registration Rights Agreement dated May 31, 2006 (Incorporated by reference to Exhibit 10.6 to Form 8-K filed on June 15, 2006)
10.47	Second Amended & Restated Mortgage dated May 31, 2006 (Incorporated by reference to Exhibit 10.7 to Form 8-K filed on June 15, 2006)
10.48	2006 Stock Option Plan (Incorporated by reference to Exhibit 10.48 to Form S-1 filed on November 1, 2006)
21	List of Subsidiaries of Petrol Oil and Gas, Inc. (Incorporated by reference to Exhibit 21 to Form 10-KSB filed on March 31, 2006)
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

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: November 9, 2006

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Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Good

Petrol Oil & Gas (POIG) Inactive 10-Q2006 Q3 Quarterly report

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