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NAMG > SEC Filings for NAMG > Form 10-Q on 20-May-2013All Recent SEC Filings

Show all filings for NORTH AMERICAN OIL & GAS CORP. | Request a Trial to NEW EDGAR Online Pro



Quarterly Report

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


This Management's Discussion and Analysis of Financial Condition and Results of Operations includes a number of forward-looking statements that reflect Management's current views with respect to future events and financial performance. You can identify these statements by forward-looking words such as "may" "will," "expect," "anticipate," "believe," "estimate" and "continue," or similar words. Those statements include statements regarding the intent, belief or current expectations of us and members of its management team as well as the assumptions on which such statements are based. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve risk and uncertainties, and that actual results may differ materially from those contemplated by such forward-look statements.

Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the Securities and Exchange Commission. Important factors currently known to us could cause actual results to differ materially from those in forward-looking statements. We undertake no obligation to update or revise forward-looking statements to reflect changed assumptions, the occurrence of unanticipated events or changes in the future operating results over time. We believe that its assumptions are based upon reasonable data derived from and known about our business and operations and the business and operations of the Company. No assurances are made that actual results of operations or the results of our future activities will not differ materially from its assumptions. Factors that could cause differences include, but are not limited to, expected market demand for the Company's services, fluctuations in pricing for materials, and competition.


We began oil and gas exploration in California in June 2011 through our subsidiary Lani. The Company is currently focused on our oil and natural gas exploration, exploitation and development operations on projects located in the San Joaquin Basin, California.

Lani drilled its inaugural exploratory well on the Tejon Ranch Extension on November 25, 2012. We completed drilling on Well 77-20 in December 2012. In the first quarter 2013 the Company tested seven (7) zones, suspending the well on February 13, 2013 to review data, secure seismic data over the leaseholds, and better determine possible future testing zones of the well. Five geological consultants are currently reviewing data from the previous testing, and analyzing purchased seismic data to determine which additional zones may be tested.

During the period ending March 31, 2013 the Company managed an aggressive acquisition program in the White Wolf prospect. Within a four (4) month period, the Company acquired additional leases in this prospect.

As of April 30, 2013, we owned interests in approximately 4,663 gross (2,339 net) acres in the White Wolf prospect, 2,874 gross (2,600 net) acres in the Tejon Main prospect, and 546 gross (44 net) acres in the Tejon Extension prospect.

The Company licensed seismic data over a thirty seven (37) mile area covering our Tejon Extension and Tejon Main prospect in February 2013. Consultants have begun the initial review of this data to provide feedback for future development of our prospects.

Consolidated Results of Operations for the Three Months Ended March 31, 2013 Compared to the Three Months Ended March 31, 2012

Revenues from Operations - Revenues for the three (3) month period ending March 31, 2013 and 2012 were $0 and $0 respectively.

Expenses from Continuing Operations - The Company incurred operating expenses of $711,337 for the three (3) month period ending March 31, 2013; an increase of $704,965 compared to $6,372 for the three (3) month period ending March 31, 2012. The operating expense increase was primarily due to an increase in geological and geophysical expenses for the purchase of a seismic data license covering thirty seven miles over two of the Company's prospects, and increased general and administrative costs. This seismic license was based on $125,000 cash payment and $235,500 in stock based payments, Increased G & A included costs of NAMOG's annual audit, tax accounting, and increased legal expense.

Other Income/Loss - For the three (3) month period ending March 31, 2013 and 2012 the Company had $0 other income. For the three (3) month period ending March 31, 2013 the Company had an increase in other expenses of ($5,650). This increase was due to California State tax franchise fees.

Liquidity - At March 31, 2013, the Company had a cash balance of $246,118 compared to March 31, 2012 where the Company had a cash balance of $31,800. This increase in cash is attributed to the November 13, 2012 Farm-in agreement with Avere Energy, and $500,000 cash attributed to the sale of 5,000,000 shares of common stock to East West Petroleum at $.10 per share.

Historically the Company has lacked liquidity, a result of insufficient financing alternatives available to the Company.

Based on current expectations, the Company believes that we are not sufficiently funded beyond June 2013. We do not have any firm commitments to raise additional capital nor is there any assurance sufficient capital will be available at acceptable terms.

The cash requirements of the Company may have a material impact on our liquidity. The reasons for this are:

The Company has only secured sufficient funds to maintain its current operations through June 30, 2013. There is an uncertainty as to whether the Company can maintain operations through the fourth quarter of 2013 without securing additional capital through cash raisings, or investor project participation; and there is no certainty that the Company can achieve profitable levels in the oil and gas exploration field, or that it will be able to raise additional capital through any means.

Critical Accounting Policies

Oil and Gas Accounting

Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information licensed for unproved acreage to assist in determining the desirability of drilling additional development wells within an area may be capitalized under the successful efforts method. These costs must meet the definition of development activities. Leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.

Property Acquisition Costs

For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.

This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for project commercialization.

Exploratory Costs

For exploratory wells, drilling costs are temporarily capitalized, or "suspended," on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of "sufficient progress" is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the mere chance that future market conditions will improve or new technologies will be found that would make the project's development economically profitable. Often, the ability to move the project into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. Once a determination is made the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense.

Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it determines the potential field does not warrant further investment in the near term. Criteria utilized in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.

Proved Reserves

Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.

Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of "proved" reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company's E&P operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as "proved

At March 31, 2013 the Company does not have any Proved Reserves.

Asset Retirement Obligations

Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and plug wells at the end of operations at operational sites. The fair values of obligations for dismantling and removing these facilities are accrued at the installation of the asset based on estimated discounted costs. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.

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