Petrol Oil & Gas (POIG) 10QSB 2005 Q2 Quarterly report (small business)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-QSB

x QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2005

[ ] 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 small business issuer as specified in its charter)

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

3161 E. Warm Springs Road

Suite 300

Las Vegas, Nevada 89120

(Address of principal executive offices)

(702) 454-7318

(Issuer’s telephone number)

Copies of Communications to:

Stoecklein Law Group

402 West Broadway, Suite 400

San Diego, CA 92101

(619) 595-4882

Fax (619) 595-4883

Check mark whether the issuer (1) 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 ____

The number of shares of Common Stock, $0.001 par value, outstanding on June 30, 2005, was 25,190,477 shares.

Transitional Small Business Disclosure Format (check one):

Yes No X

PART I -- FINANCIAL INFORMATION

Item 1. Financial Statements.

Petrol Oil and Gas, Inc.

Condensed Balance Sheet

Unaudited

	June 30, 2005
Assets
Current assets:
Cash	$ 494,350
Accounts receivable	849,864
Prepaid expenses and other current assets	22,154
Investment	17,364
Total current assets	1,383,732
Fixed assets, net	1,764,356
Other assets:
Oil and gas properties using full cost accounting:
Properties not subject to amortization	1,291,461
Properties subject to amortization	12,013,579
Capitalized loan costs, net	576,500
Total other assets	13,881,540
	$ 17,029,628
Liabilities and stockholders' equity
Current liabilities:
Accounts payable	$ 235,339
Accrued liabilities	282,781
Short-term derivative liability	588,680
Current portion of long term debt	1,602,069
Total current liabilities	2,708,869
Long-term debt, less current portion	4,561,372
Asset retirement obligation	675,464
Contingencies and commitments
Stockholders' equity:
Preferred stock, $0.001 par, authorized 10,000,000 shares; no shares issued	-
Common stock, $0.001 par, authorized 100,000,000 shares; 25,190,477 issued and outstanding	25,190
Stock bought for services not issued	130
Unamortized cost of stock or options issued for services	(39,192)
Additional paid-in capital	18,956,017
Other comprehensive (loss)	(588,680)
Accumulated (deficit)	(9,269,542)
Total stockholders' equity	9,083,923
	$ 17,029,628

See notes to condensed financial statements.

2

Petrol Oil and Gas, Inc.

Condensed Statement of Operations

Unaudited

	Six Months Ended June 30,		Three Months Ended June 30,
	2005	2004	2005	2004
Revenue:	$ 2,996,102	$ -	$ 1,805,491	$ -
Expenses:
Direct operating costs	1,711,852	-	1,293,851	-
Professional and consulting fees	1,554,434	867,737	141,854	82,718
General and administrative	620,341	532,958	320,223	597,133
Depreciation, depletion and amortization	582,104	3,173	232,650	1,718
Acquisition costs	-	654,000	-	-
Total expenses	4,468,731	2,057,868	1,988,578	681,569
Loss from operations	(1,472,629)	(2,057,868)	(183,087)	(681,569)
Other income (expense):
Interest and other income	23,910	22,669	10,257	2,742
Interest expense	(853,433)	(1,715)	(457,618)	(762)
Other income (expense)	(829,523)	20,954	(447,361)	1,980
Loss before income tax	(2,302,152)	(2,036,914)	(630,448)	(679,589)
Provision for income tax	-	-	-	-
Net loss	$ (2,302,152)	$ (2,036,914)	$ (630,448)	$ (679,589)
Basic and diluted earnings per share	$ (0.09)	$ (0.12)	$ (0.03)	$ (0.04)
Weighted shares outstanding	24,962,730	16,448,261	25,096,052	16,448,261

See notes to condensed financial statements.

3

Petrol Oil and Gas, Inc.

Condensed Statement of Cash Flows

(Unaudited)

	Six Months Ended June 30,
	2005	2004
Operating activities:
Net loss	$ (2,302,152)	$ (2,036,914)
Adjustments to reconcile net loss to cash used in operating activities-
Depreciation, depletion and amortization	583,221	3,173
Accretion of warrants issued for long-term debt	503,785	-
Accretion of asset retirement obligations	23,347	-
Stock and warrants issued for services	(1,189,420)	913,313
Stock issued for interest payments	297,833	-
Stock issued in acquisition of CBM	-	765,000
Change in assets and liabilities-
Increase in accounts receivable	(536,882)	-
Increase in prepaid expense and other current assets	(10,628)	66,632
Increase in investments	(1,585)	(14,882)
Decrease in accounts payable	(195,059)	(124,549)
Decrease in accrued liabilities	(25,163)	(24,206)
Decrease in accrued liability – related parties	(270,000)	-
Decrease in note payable – related party	-	(47,500)
Cash used in operating activities	(743,863)	(499,933)
Investing activities:
Equipment purchased	(115,997)	(2,760)
Investment	-	200,000
Reductions to restricted cash	852,346	-
Additions to oil & gas properties	(1,058,666)	(968,601)
Cash (used in) investing activities	(322,317)	(771,361)
Financing activities:
Payments made on long-term debt	(232,355)	(2,734)
Borrowings on note payable	-	250,000
Payments received on note receivable	-	13,732
Exercise of options	-	187,500
Cash provided by (used in) financing activities	(232,355)	448,498
Decrease in cash	(1,298,535)	(822,796)
Beginning cash	1,792,885	1,059,838
Ending cash	$ 494,350	$ 237,042
Supplemental cash flow information:
Interest paid in cash	$ 65,710	$ 1,715
Income taxes paid	-	-
Non cash financing activities:
Unamortized cost of stock and options issued for services	$ 40,200	$ 950
Stock for services not issued	-	475
Stock, warrants and options issued for services	1,189,490	913,313
Stock issued for interest	297,833	-
Stock issued and exercise of options for a note receivable	-	350,000
Asset retirement obligation	206,500	-

See notes to condensed financial statements.

4

Petrol Oil and Gas, Inc.

Notes To Condensed Financial Statements

Note 1 - Basis of Presentation

The unaudited condensed financial statements have been prepared in accordance with United States generally accepted accounting principles for interim financial information and with the instructions to Form 10-QSB and reflect all adjustments which, in the opinion of management, are necessary for a fair presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim period are not necessarily indicative of the results to be expected for a full year. Certain amounts in the prior year statements have been reclassified to conform to the current year presentations. These statements should be read in conjunction with the financial statements and footnotes thereto included in the Form 10-KSB for the year ended December 31, 2004.

Note 2 - Stock Transactions and Consulting Agreements

On January 11, 2005, the Company awarded Mr. David Polay 50,000 shares and Mr. LoCascio 10,000 shares of its common stock for services. The value of the stock was determined based on the closing value of its stock on the date the stock was issued. The Company recorded $141,000 as professional fee expense.

On January 11, 2005, the Company issued 60,000 shares of its common stock in lieu of cash compensation to Russell A. Frierson for land and administrative support rendered to the Company. The value of the stock was determined based on the closing value of its stock on the date the stock was issued. The Company recorded $141,000 as professional fee expense.

On January 11, 2005, the Company issued 100,000 shares of its restricted common stock to Gary Bridwell. The Company had recorded the par value of the stock as stock bought for services not issued at December 31, 2004 so this reduced that account by $100.

On February 7, 2005, the Company entered into a Consulting Agreement with CEOcast, Inc., wherein the Company agreed to issue 40,000 shares of its common stock to CEOcast. The value of the stock was determined based on the closing value of the stock on the date the stock was issued. The Company recorded $96,800 as professional fee expense. The stock has not been issued as of June 30, 2005.

Pursuant to a consulting agreement the Company will issue stock to ECON Investor Relations, Inc based on a

monthly value of $6,000. For the first and second quarters of 2005 the Company recorded $36,000 as a professional fee expense. The stock was not issued as of June 30, 2005.

On January 28, 2005, in exchange for delaying its monthly principal payment until June 2005 on the note due to Laurus, the Company issued to Laurus 666,667 warrants at an exercise price of $2.50 and 333,333 warrants at an exercise price of $3.00. The Company recorded as professional fee expense $549,000, which represented the fair market value of the warrants based on the Black-Scholes pricing model.

On March 16, 2005, the Company executed an agreement with CSC Group, wherein Steve Cochennet, (an Advisory Board Member) President of CSC Group, agreed to provide the Company with services to further its long-term strategy. The term of the agreement began on January 1, 2005. The Company agreed to pay Mr. Cochennet $5,000 per month plus grant 150,000 options to CSC Group at $2.04 per share for a period of five years. Mr. Cochennet will also receive 3% of any debt facility or mezzanine financing he puts in place prior to December 31, 2005. The value of the warrants was $138,795 as calculated by using the Black-Scholes pricing model. This was recorded as professional fee expense.

5

Petrol Oil and Gas, Inc.

Notes To Condensed Financial Statements

On March 18, 2005, the Company executed an agreement with Robert Howell, (an Advisory Board Member) wherein Mr. Howell agreed to provide the Company with services on specified assignments as needed by the Company. The term of the agreement is for three months and began on February 1, 2005. The Company agreed to compensate Mr. Howell $10,000 for each month plus pay for all reasonable business and travel expenses, and grant Mr. Howell 125,000 options to purchase its common stock at a price equal to the average of the last 22 trading days ending April 29, 2005. The options will be fully vested and will have five years in which to exercise them. If Mr. Howell is involved in finding sources of debt for the Company, he will work with Mr. Cochennet and be paid an additional fee by Mr. Cochennet. The value of the warrants was $86,825 as calculated using the Black-Scholes pricing model. This was recorded as professional fee expense.

On May 9, 2005, the Company entered into an agreement with an employee to provide services to the Company. As part of the agreement the employee will receive 60,000 options vesting 20,000 per year at $2.33 per share for a period of five years. The value of the options was $40,200 as calculated using the Black-Scholes pricing model. The value was recorded as unamortized cost of options issued for compensation and will be amortized over the vesting period. At June 30, 2005 $1,117 has been expensed.

A summary of stock options and warrants is as follows:

	Options		Warrants
Outstanding 12/31/04	1,700,000	$1.24	17,761,666	$1.49
Granted	335,000	2.11	1,000,000	2.67
Cancelled	--	--	--	--
Exercised	--	--	--	--
Outstanding 3/31/05	1,975,000	$1.38	18,761,666	$1.55

In the first and second quarters of 2005, Laurus Master Fund, Ltd. converted $526,225.87 of interest and principal due under the Convertible Term Note. Pursuant to the conversion rate of $1.50 per share, the Company issued 350,817 shares of its common stock through June 30, 2005.

At June 30, 2005, the Company had approximately 131,000 shares of its common stock that is earned but not issued.

Note 3 – Asset Retirement Obligation

The Company’s 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.

	June 30, 2005
Asset retirement obligation, beginning of year	$ 445,617
Liabilities incurred during the year	206,500
Liabilities settled during the year	--
Accretion of expense	23,347
Asset retirement obligations, end of year	$ 675,464

6

Petrol Oil and Gas, Inc.

Notes To Condensed Financial Statements

Note 4 - Long-Term Debt

Long-term debt consists of the following:

	June 30, 2005
Convertible Note payable – Laurus Master Fund	$ 7,543,235
Note payable – GMAC	18,900
Total	7,562,135
Less unamortized cost of warrants	(1,398,695)
	6,163,440
Less current portion	(1,602,068)
Total long-term debt	$ 4,561,372

For the quarter and six-month period ended June 30, 2005 the accretion of the warrants that was included in interest expense totaled $248,704 and $503,785, respectively.

In June 2005, the Company signed a revolving term loan with Cornerstone Bank for $1 million to use as working capital. The term of the loan is for one year and is due in June 2006 and is collateralized by various Company bank accounts at Cornerstone Bank. As of June 30, 2005, there was no outstanding balance under this loan.

Note 5 – Fixed Price Sales Contracts

The Company entered into various contracts with Seminole Energy Services LLC to sell 60,000 mmbtu per month for the period of July 2005 to February 2006 at various fixed prices with the overall average price of $6.01.

Note 6 - Subsequent Events

On July 6, 2005, Laurus Master Fund, Ltd. converted $228,382.28 of principle and $56,916.84 of accrued interest due under the Convertible Term Note. Pursuant to the conversion rate of $1.50 the Company issued 190,200 shares of its restricted common stock to Laurus on July 8, 2005.

On July 20, 2005, Goran Blagojevic exercised 100,000 warrants at a price of $0.75 per share. The 100,000 shares were issued on July 29, 2005 and were previously registered in the Company’s registration statement declared effective on June 30, 2005.

On August 8, 2005, the Company issued 22,785 shares of its restricted common stock (valued at $54,000) to ECON Investor Relations, Inc. pursuant to its consulting agreement dated June 15, 2004.

7

FORWARD-LOOKING STATEMENTS

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

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

Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in any 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;

• loss of customers or sales weakness;

• 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 “Factors That May Affect Our Results of Operation” in this document and in our Annual Report on Form 10-KSB for the year ended December 31, 2004.

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 conventional gas.

8

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 would provide ready sales market for our produced gas. Our focus now turns to developing and producing those leases so as to realize the value held in them. With 169,000 gross leased acres the task of developing the properties with wells on 160 acre spacing will involve in excess of 1,000 wells.

Our producing leases known as Petrol-Neodesha, in the Neosho and Wilson counties, account for approximately 10,000 of the total 169,000 gross (137,000 net) leased acres. These properties are in active production with 77 CBM producing wells that produce approximately 3.0 million cubic feet of gas per day (2.17 Million cubic feet per day of net production of the Company). Studies to drill additional wells, improve existing wells and enhance the gas gathering system were refined into an advanced development plan during the first quarter of 2005 and portions of the plan were executed in the second quarter of 2005. This plan will serve as the blueprint to enhance the value of these properties and provide knowledge for development of remaining leases in other nearby counties where the company has leases. These properties have provided the Company with a revenue stream and certain value in proven producing reserves.

In the second quarter of 2005, we implemented Phase I of our development plan that involved expanding the production of our existing gas gathering pipeline and drilling several new production wells. Phase I pipeline enhancements included adding approximately 3.5 miles of high capacity gas gathering pipeline and strategically incorporating 2 new booster stations to reduce pipeline pressure and provide a higher level of compressor redundancy. In addition, the reduced pipeline pressure was designed to increase CBM production from existing production wells and in fact overall field production was found to increase by about 425 Mcfd. Furthermore, the capacity of the pipeline has now been doubled and will serve to accommodate production from new development wells.

The second element of the Phase I development plan involved drilling five new CBM wells. Four of our five new wells are in various stages of completion and have increased gas production by 150 Mcfd after approximately six weeks of de-watering. These new wells are the first set of wells we have completed and connected to our newly enhanced gas gathering pipeline system. Based on our current field production levels, we plan to aggressively develop future production activities.

Additionally, in the second quarter of 2005, we acquired an additional 400 gross acres adjacent to our Petrol-Neodesha property and have committed to drill three wells this year on these newly acquired leases.

We intend to continue seeking acquisition opportunities which compliment our current production. We intend to fund our development activity primarily through use of cash flow from operations and cash on hand, while seeking larger debt funding opportunities sufficient enough to develop a greater portion of our mineral leases.

We have developed and circulated an information package to seek funds for the development of our Coal Creek project in Coffey County, Kansas. The Coal Creek development plan is based upon drilling and completing some 540 wells over a two year period along with three gas gathering pipelines. The full development plan is expected to be executed in two phases. The first phase involves emplacing the basic gas gathering pipeline infra-structures and developing about 180 new CBM wells. Phase two includes finalizing the gas gathering pipeline and developing 360 new CBM wells. The anticipated costs of the full development plan is approximately $66,000,000 for which we expect to acquire funding through a debt structure from banks or mezzanine financiers. 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.

9

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

Results of Operations

The following overview provides a summary of key information concerning our financial results for the three months ended on June 30, 2005 and 2004.

	Three Months Ended June 30,
	2005	2004	Increase
	Amount	Amount	(Decrease)
Revenue	$       1,805,491	$                     -	$         1,805,491
Expenses:
Direct operation costs	1,293,851	-	1,293,851
General and administrative	320,223	597,133	(276,910)
Professional and consulting fees	141,854	82,718	59,136
Depreciation, depletion and amortization	232,650	1,718	230,932
Acquisition cost	-	654,000	(654,000)
Total expenses	1,988,578	681,569	1,307,009
Loss from operations	(183,087)	(681,569)	(498,482)
Other income (expense):
Interest and other income	10,257	2,742	7,515
Interest expense	(457,618)	(762)	456,856
Net loss	$        (630,448)	$         (679,589)	(49,141)

Three Months Ended in 2005 Compared to Three Months Ended in 2004

Revenue: Total revenue was $1,805,491 and $-0- for the second quarter of 2005 and 2004, respectively. Historically, the Company has been in a development stage, acquiring various mineral leases and implementing all necessary capital improvements in order to become efficient in our production efforts. Our increase in revenue during the second quarter of 2005 is attributable to the acquisition of producing properties in Wilson and Neosho counties of Eastern Kansas during the fourth quarter of 2004. Also, during the second quarter of 2005, the Company increased the number of oil wells producing in various counties in Southeastern Kansas.

Direct operating costs are the costs associated with operating producing wells, and transporting the oil and natural gas to the market for sale. Operating costs totaled $1,293,851 and $-0- for the second quarter of 2005 and 2004, respectively, because there were no producing properties in 2004. This was and increase of $875,850 from the first quarter of 2005, which was due to extensive work over and repair cost on the Company’s oil properties during the second quarter.

10

Professional and consulting fees were $141,854 and $82,718 for the second quarters of 2005 and 2004, respectively, an increase of $59,136. The increase is a result of increased oil and gas operations and increased legal and accounting fees associated with the increased operations during 2005.

General and administrative expenses for the second quarter of 2005 were $320,223 compared to $597,133 in the second quarter of 2004, respectively, for a decrease of $276,910. The decrease is attributable to high loan fees in 2004.

Depreciation, depletion and amortization expense for the second quarter of 2005 and 2004 were $232,650 and $1,718 for an increase of $230,932. Historically, as a development stage company, we had not placed in service depreciable assets nor had we begun production eliminating the need for a depletion expense. The increase was a result of recently completed acquisition obligations and commencement of production.

Other Income (Expense):

Interest and other income for the second quarter of 2005 and 2004 was $10,257 and $2,742, respectively, for a increase of $7,515 which was the result of increased cash in 2005 due to the Laurus restricted funds account.

Interest Expense for the second quarter of 2005 and 2004 was $457,618 and $762, respectively, for an increase of $456,856. During the fourth quarter of 2004, we issued a long-term convertible note in the amount of $8,000,000 and the interest and accretion of warrant cost is associated with the note.

Net Loss: Our net loss for the second quarter of 2005 and 2004 was $630,448 and $679,589, respectively, for a decrease in net loss in the amount of $49,141. The Company had a $498,482 decrease in loss from operation due to the purchase of producing properties in November 2004, offset an increase of $456,856 interest expense due to the Laurus financing to purchase the producing properties.

The following overview provides a summary of key information concerning our financial results for the six months ended on June 30, 2005 and 2004.

	Six Months Ended June 30,
	2005	2004	Increase
	Amount	Amount	(Decrease)
Revenue	$ 2,996,102	$ -	$ 2,996,102
Expenses:
Direct operation costs	1,711,852	-	1,711,852
General and administrative	620,341	532,958	87,383
Professional and consulting fees	1,554,434	867,737	686,697
Depreciation, depletion and amortization	582,104	3,175	578,931
Acquisition cost	-	654,000	(654,000)
Total expenses	4,468,731	2,057,868	2,410,863
Loss from operations	(1,472,629)	(2,057,868)	(585,239)
Other income (expense):
Interest and other income	23,910	22,669	1,241
Interest expense	(853,433)	(1,715)	851,718

11

Net loss $(2,302,152) $(2,036,914) 265,238

Six Months in 2005 Compared to Six Months Ended in 2004

Revenue: Total revenue for the six months ended in 2005 and 2004 was $2,996,102 and $0. Historically, the Company has been in a development stage, acquiring various mineral leases and implementing all necessary capital improvements in order to become efficient in our production efforts. Our increase in revenue during the six months of 2005 is attributable to the acquisition of the producing properties in Wilson and Neosho counties of Eastern Kansas during the fourth quarter of 2004.

Expenses:

Direct operating costs are the costs associated with operating producing wells, and transporting the oil and natural gas to the market for sale. Operating costs totaled $1,711,852 and $0 for the six months ended in 2005 and 2004, respectively, because there were no producing properties in 2004. Direct operating cost for the six months for gas wells and oil wells was $1,114,638 and $597,241, respectively.

Professional and consulting fees were $1,554,434 and $867,737 for the six months ended in 2005 and 2004, for an increase of $686,697. The increase is a result of our endeavors to obtain the necessary capital required to ultimately increase revenue. Our efforts have led us to various individuals with which we have entered into consulting agreements for services.

General and administrative expenses for the six months ended in 2005 and 2004 was $620,341 and $532,958, respectively, for an increase of $87,383. The increase is attributable to the additional overhead incurred in connection with the commencement of field operations.

Depreciation, depletion and amortization expense for the six months ended in 2005 and 2004 were $582,104 and $3,173. Historically, as a development stage company, we had not placed in service depreciable assets nor had we begun production eliminating the need for a depletion expense. The increase was a result of recently completed acquisition obligations and commencement of production.

Acquisition costs in the six months ended 2004 was the non-allocable amounts associated with the purchase of oil and gas assets.

Other Income (Expense):

Interest and other income for the six months ended in 2005 and 2004 was $23,910 and $22,669, respectively, for a increase of $1,241, which was the result of increased restricted funds as a result of the Laurus financing.

Interest Expense for the six months ended in 2005 and 2004 was $853,433 and $1,715, respectively, for an increase of $851,718. During the fourth quarter of 2004, we issued a long-term convertible note in the amount of $8,000,000 and the interest and accretion of warrant cost is associated with the note.

Net Loss: Our net loss for the six months of 2005 and 2004 was $2,302,152 and $2,036,914, respectively, for an increase loss in the amount of $265,238. The net loss was primarily attributable to us beginning our production and the increased interest expense directly associated with our current financing arrangements.

12

Operation Plan

During the next twelve months we plan to continue to focus our efforts on the sustained development and production of CBM on our existing properties, pursuing strategic acquisitions of producing properties and creating value by furthering our business plan.

We have developed and circulated an information package to solicit funds for the development of our Coal Creek project in Coffey County, Kansas. The Coal Creek development plan includes drilling and completing some 540 wells over a two year period along with three gas gathering pipelines. The anticipated costs of the full development plan is approximately $66,000,000 for which we expect to acquire funding through a debt structure from banks or mezzanine financiers. The pace of the development will obviously depend on the availability of the financing program. We also intend to fund portions of our field operations and development program from revenues obtained from sales of our CBM gas and oil production, from outside lenders, and from proceeds of anticipated exercise of warrants and options. In addition, we may take on Joint Venture (JV) or Working Interest (WI) partners that will contribute to the capital costs of drilling and completion and then share in revenues derived from production. This economic strategy may allow us to realize the value in our own financial assets toward the growth of our leased acreage holdings, pursue the acquisition of strategic oil and gas producing properties or companies and generally expand our existing operations.

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.

With the acquisition of the Petrol-Neodesha and certain oil properties, we are currently providing ongoing revenue and cash from these properties. As we expand operational activities, we will weigh the pace of further drilling and development against the availability of internal and external funding.

Liquidity and Capital Resources

Financing. On October 28, 2004, we entered into agreements with Laurus Master Fund, Ltd., a Cayman Islands corporation. Under the terms of the Laurus Funds agreements we issued a Secured Convertible Term Note (the “Note”) in the aggregate principal amount of $8.0 million and a five-year warrant (the “Warrant”) to purchase 3,520,000 shares of our common stock at $2.00 per share and 1,813,333 shares of our common stock at $3.00 per share. The Note is convertible into shares of our common stock at a fixed conversion price of $1.50 per share. The Note has a three-year term and bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3%, subject to a floor of 7.5% per annum.

On January 28, 2005, we amended the Laurus Funds Secured Convertible Term Note and the Registration Rights Agreement. Laurus agreed to move six months of principal payments (January through May of 2005) to be paid on the Maturity Date (October 28, 2007). Additionally, Laurus agreed to extend certain filing and effectiveness dates under the registration rights agreement. In consideration for the amendment, we issued an additional common stock purchase warrant to Laurus to purchase up to 1,000,000 shares of our common stock at $2.50 per share for the first 666,667 shares and $3.00 per share for the next 333,333 shares. Further, we are required to file a registration statement covering the new warrant on or before August 1, 2005.

13

As of July 6, 2005, Laurus has converted $456,764.56 of principal payments into 304,510 shares of our common stock and $354,760.43 of accrued interest into 236,507 shares of our common stock (541,017 shares in total). The conversion of accrued interest allowed us access to additional cash to use in our operations.

Pursuant to the terms of the Registration Rights Agreement between Laurus and us, we were obligated to file a registration statement covering shares of our common stock issuable upon conversion of the Note and exercise of the Warrant. A registration statement was declared effective by the SEC on June 30, 2005. Pursuant to Amendment No. 1 to the Registration Rights Agreement, we were obligated to file a registration statement registering the 1,000,000 shares of our common stock issuable upon exercise of the New Warrant. We filed a registration statement with the Securities and Exchange Commission relating to the resale of our common stock on August 1, 2005. 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.

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

In October 2004 we sold 5,633,333 units for a total purchase price of $6,760,000. As part of the unit offering, we were required to use commercially reasonable efforts to file a registration statement with the SEC covering the units and have the registration declared effective within 120 days of the last Closing under the unit offering. On October 29, 2004, we filed a registration statement on Form SB-2 which included the units and was declared effective on June 30, 2005. The subscription agreement for the unit offering contains a liquidated damage clause calling for us to pay damages ranging from 1%-2% for each thirty day period the registration statement is not effective as follows; (i) 1% of the purchase price of the Units for the first 30 day period, (ii) 1.5% of the purchase price of the Units for the second 30 day period, and (iii) 2% of the purchase price of the Units for each 30 day period thereafter (i) and (ii). We believe we used commercially reasonable best efforts in an attempt to have the registration statement declared effective and therefore will not be subject to payment of the liquidated damages. However, in the event we are required to pay the liquidated damages, the impact on our operations could be material.

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 the Savage (Petrol-Neodesha) acquisition, 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 significantly curtail our operations. This would materially impact our ability to continue operations.

We have used the funds remaining in the Laurus restricted account and completed the first phase of our operations which is large field scale development. However, we anticipate the need for a significant amount of funds in order to fully develop both the Petrol-Neodesha property and our leased acreage.

Over the next twelve months we believe that our existing capital combined with cash flow from operations will not be sufficient to sustain operations and planned expansion without additional financing.

14

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

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

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

Field Development

Our original plan of operation 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 enough land to move forward with our field development and with the proceeds of our unit offering, combined with approximately $850,000 being held in a restricted account by Laurus, we are proceeding with the next phase of our operations which is large field scale development.

Our Petrol-Neodesha project has spacing for at least another 50 wells to fully develop this existing leased acreage. In addition we are in the process of enhancing our gas gathering system with the addition of a set of new booster pumps and larger diameter trunk lines. Finally, we have instituted a well remediation program for some older producing wells that is anticipated to also enhance production.

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

Our Reserve Report dated December 31, 2004 indicates Petrol has Proven Undeveloped gas reserves on its leases in the Coal Creek Project totaling 1.08 Billion cubic feet and Probable Net reserves of approximately 1.01 Billion cubic feet. Various alternatives for further development of the field and the gas gathering infrastructure in this project are currently being evaluated.

In the field development stages of our plan, each new well will be drilled and tested individually. The well, upon a favorable evaluation of its producing capabilities, will be fully completed and connected to our local gas gathering and water disposal pipelines.

When we have identified a proposed drilling site, we as a licensed operator in the State of Kansas and Missouri, will be engaged in all aspects of well site operations. As the operator we will be responsible for permitting the well, which will include obtaining permission from the Kansas Oil and Gas commission or

15

Missouri relative to spacing requirements and any other state and federal environmental clearances required at the time that the permitting process commences. Additionally, we will formulate and deliver to all interest owners an operating agreement establishing each participant’s rights and obligations in that particular well based on the location of the well and the ownership. In addition to the permitting process, we as the operator will be responsible for hiring the driller, geologist and land men to make final decisions relative to the zones to be targeted, confirming that we have good title to each leased parcel covered by the spacing permit and to actually drill the well to the target zones. We will be responsible for completing each successful well and connecting it to the most appropriate portion of our gas gathering system.

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

Kansas Geologic Society (KGS) joined us in our scientific effort designed to assess the gas reserves from our CBM exploratory/test wells in eastern Kansas. KGS took samples from coal beds found in our Coffey County wells. Their laboratory test results yielded similar gas content values to those obtained by our geologist, Mr. William Stoeckinger, that were derived from sampling of our other exploratory/test wells. We view these independent gas content values quite favorably since they indicate quantitative similarities to the CBM producing coal beds found in other counties to the south. Woodson county being adjacent to Coffey county.

Based on our first series of exploratory/test wells we anticipate that each well in our targeted area will cost approximately $30,000 to locate, drill and test, an additional $105,000 to complete, plus an additional $1,000 per month per well to pay for electricity, pulling and repairs, pumping 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.

Along with the drilling and completion of our CBM production wells Petrol will formulate, design and install a gas gathering and compression system to transport the gas from wellhead to the high pressure interstate pipeline tap and sales market. Our experience in Petrol-Neodesha will be brought to bear on these new areas in Coal Creek or Missouri. We have identified several major interstate distribution pipelines that operate within and pass through the counties in which we have lease holdings. These include pipelines owned and operated by Southern Star, CMS Energy, Enbridge and Kinder Morgan. We have initiated contact with two of 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.

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

16

The prices obtained for oil and gas are dependent on numerous factors beyond our control, including domestic and foreign production rates of oil and gas, market demand and the effect of governmental regulations and incentives. We have entered into forward sales contracts for a portion of the gas and oil we presently produce. We do not have any delivery commitments for gas or oil from wells not currently drilled. However, due to the U.S. government’s recent push toward increased domestic production of energy sources, and the high demand for natural gas, we do not anticipate any difficulties in selling any oil and gas we produce, once it has been delivered to a distribution facility.

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

Significant changes in the number of employees.

We currently have four full time employees and two part time employees as well as eight contract personnel that support and operate our field operations. As drilling production activities increase, we intend to hire additional technical, operational and administrative personnel as appropriate. None of our employees are subject to any collective bargaining agreements; however, we have entered into employment agreements with Paul Branagan and Gary Bridwell. We expect a significant change in the number of full time employees over the next 12 months. However, at this time we are unable to quantify exactly how many. We intend to use the services of independent consultants and contractors to perform various professional services, particularly in the area of land services, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain general and administrative expenses.

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

Resignation and Appointment of Officer

Effective May 9, 2005, John Garrison resigned as Chief Financial Officer of the Company. Concurrently, the board of directors appointed Lawrence Finn as Vice President and Chief Financial Officer of the Company.

Lawrence Finn, is Vice President and Chief Financial Officer of the Company. Prior to joining Petrol, Mr. Finn worked for CDX Gas, LLC, a private natural gas company with operations in the U.S. and Canada, concentrating in coal bed methane extraction. At CDX, Mr. Finn worked was the Vice President of Finance and then as Manager of Shale Projects. As Vice President of Finance, Mr. Finn was responsible for all financial reporting, accounting, and compliance with all financial obligations. As Manager of Shale Projects, Mr. Finn was responsible for identifying and attracting partners in development projects in Michigan, Indiana and Northern Kentucky. Prior to CDX, he served as Vice President Finance and Chief Financial Officer of The Wiser Oil Company for seven years. At Wiser, Mr. Finn was Mr. Finn was directly responsible for commercial and investment banking, corporate planning, investor relations, corporate communications and tax reporting for operations in the United States, Canada, and South America. He is certified Public Accountant and has a B.B.A. from the University of Houston.

17

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

Description of contracts.

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.

Critical Accounting Policies and Estimates

Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these 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 at the date of our financial statements. 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. Our significant accounting policies are detailed in Note 1 to our financial statements included in our Annual Report filed on June 9, 2005. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.

Revenue Recognition.    It is our policy to recognize revenue when production is sold to a purchaser at a fixed or determinable price.

Full Cost Method of Accounting.    We account for our oil and natural gas operations using the full cost method of accounting. Under this method, all costs associated with property acquisition, exploration and development of oil and gas reserves are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and cost of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. All of our properties are located within the continental United States.

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost, or estimated fair value, if lower of unproved properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues is computed by applying current prices of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions.

18

Oil and Natural Gas Reserve Quantities.    Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions.

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.

Quantitative and Qualitative Disclosure About Market Risk

Commodity Price Risk

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 current long term debt with Laurus Funds has a floating interest rate, with a floor of 7.5%.  Therefore, interest rate changes will impact future results of operations and cash flows.

FACTORS THAT MAY AFFECT OUR RESULTS OF OPERATION

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

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

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

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.

19

We have and expect to continue to have substantial capital expenditure and working capital needs. We believe that current cash on hand and the other sources of liquidity are only sufficient enough to fund our operations through fiscal 2005. 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.

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

We intend to 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

20

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.

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

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

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:

21

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

• the domestic and foreign supply of natural gas and oil;

• weather conditions;

• domestic and foreign governmental regulations;

• political conditions in natural gas and oil producing regions;

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

• the price and availability of other fuels.

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

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 and development stage operations, our estimates may not be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development expenditures and operating expenses will likely vary from those anticipated. These variances may be material.

22

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

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

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

• fires;

• explosions;

• blow-outs and surface cratering;

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

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

• pipe, cement, or pipeline failures;

• casing collapses;

• embedded oil field drilling and service tools;

• abnormally pressured formations; and

• environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

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

• injury or loss of life;

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

• pollution and other environmental damage;

• clean-up responsibilities;

• regulatory investigation and penalties;

• suspension of our operations; and

• repairs to resume operations.

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

The unavailability or 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

23

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.

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

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

• location and density of wells;

• the handling of drilling fluids and obtaining discharge permits for drilling operations;

• accounting for and payment of royalties on production from state, federal and Indian lands;

• bonds for ownership, development and production of natural gas and oil properties;

• transportation of natural gas and oil by pipelines;

• operation of wells and reports concerning operations; and

• taxation.

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

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

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

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.

24

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

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

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

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

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

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

• Our management’s attention may be diverted; or

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

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

Risks Associated with Laurus Funds Financing

We have substantial indebtedness to Laurus Master Fund, Ltd. which is secured by certain assets acquired from Savage Resources, LLC and Savage Pipeline, LLC. If an event of default occurs under the secured note issued to Laurus Funds, Laurus Funds may foreclose on these assets and we may be forced to curtail our operations or sell some of these assets to repay the note.

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

25

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 the acquired assets or be forced to materially reduce our business activities.

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

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

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

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. On July 29, 2005, the closing price of our stock was $1.55. The convertible note has a conversion price of $1.50. Thus the conversion rights granted to Laurus were at a discount to the recent closing price of the common stock. 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.

Item 3. 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, our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls

26

and procedures. Based on the evaluation, which disclosed no significant deficiencies or material weaknesses, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective. 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 2. Unregistered Sales of Equity Securities and Use of Proceeds.

On April 13, 2005, Laurus Master Fund, Ltd. converted $52,819.75 of accrued interest due under the Convertible Term Note. Pursuant to the conversion rate of $1.50 we issued 35,213 shares of our restricted common stock to Laurus on April 19, 2005. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).

On April 29, 2005, Laurus Master Fund, Ltd. converted $112,500 of principal into 75,000 shares under the Convertible Term Note. We issued the 75,000 shares of our restricted common stock to Laurus on May 5, 2005. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).

Pursuant to Mr. Lawrence Finn’s employment agreement effective May 9, 2005, we granted Mr. Finn options to purchase 60,000 shares of our common stock at $2.23 per share with a vesting plan of 33% per year for 3 years. We believe that the grant of the option was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).

On May 12, 2005, Laurus Master Fund, Ltd. converted $115,882.28 of principal and $54,346.47 of accrued interest due under the Convertible Term Note. Pursuant to the conversion rate of $1.50 we issued 113,486 shares of our restricted common stock to Laurus on May 17, 2005. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).

Subsequent Issuances

On July 6, 2005, Laurus Master Fund, Ltd. converted $228,382.28 of principle and $56,916.84 of accrued interest due under the Convertible Term Note. Pursuant to the conversion rate of $1.50 we issued 190,200 shares of our restricted common stock to Laurus on July 8, 2005. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).

On July 20, 2005, Goran Blagojevic exercised 100,000 warrants at a price of $0.75 per share. The 100,000 shares were issued on July 29, 2005 and were previously registered in our registration statement declared effective on June 30, 2005.

27

On August 8, 2005, we issued 22,785 shares of our common stock (valued at $54,000) to ECON Investor Relations, Inc. pursuant to its consulting agreement dated June 15, 2004. We believe that the issuance of the shares and grant of the options were exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2).

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.

31.1*	Certification of Paul Branagan, CEO pursuant to Section 302 of the Sarbanes-Oxley Act
31.2*	Certification of Lawrence Finn, CFO pursuant to Section 302 of the Sarbanes-Oxley Act
32.1*	Certification of Paul Branagan, CEO pursuant to Section 906 of the Sarbanes-Oxley Act
32.2*	Certification of Lawrence Finn, CFO pursuant to Section 906 of the Sarbanes-Oxley Act

* 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/Lawrence Finn
	Lawrence Finn, Chief Financial Officer
	(On behalf of the registrant and as
		principal accounting officer)

Date: August 15, 2005

28