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NAMG > SEC Filings for NAMG > Form 10-Q on 12-Aug-2013All Recent SEC Filings

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

Form 10-Q for NORTH AMERICAN OIL & GAS CORP.


12-Aug-2013

Quarterly Report


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

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

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.

Overview

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; specifically our Tejon Main prospect, Tejon Extension prospect, and White Wolf project.

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 have reviewed the data from the previous testing, and analyzed purchased seismic data to determine which additional zones may be tested. Lani has budgeted to reopen the Well 77-20 third quarter 2013 for further testing at a budgeted cost of Lani's share at $100,000. This testing, however, is predicated on the Company's ability to raise sufficient capital to proceed.

During the period ending June 30, 2013 the Company managed an aggressive acquisition program in the White Wolf prospect. Within a six (6) 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 (246 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 reviewed the data, and in the scope of this review, located approximately fourteen (14) prospects for further evaluation.

The Company has budgeted to drill a well on the Tejon Main prospect, subject to available funding in mid-2014 subject to the Company's ability to raise sufficient capital to fund the project.


Projects in the next 12 months, subject to raising the capital requirements:

Subject to obtaining additional financing, the following drilling and testing may be pursued. The projects and our share of the estimated costs are listed below:

Estimated cost based on expected participating working interest.

           Project           Current WI%   No. Wells   Procedure   Est. Cost

           Tejon Main            40%           1       New Drill    $2.5MM
           Tejon Extension       75%           1       New Drill    $1.0MM

Consolidated Results of Operations for the Six Months Ended June 30, 2013 Compared to the Six Months Ended June 30, 2012

Expenses from Operations - The Company incurred operating expenses of $1,037,428 for the six (6) month period ending June 30, 2013; an increase of $1,003,245 compared to $34,183 for the six (6) month period ending June 30, 2012. The operating expense increase was primarily due to an increase in exploration and leasehold costs, as well as a general increase in overall general and administrative costs associated with running a public company, including additional wages and salaries.

Other Income/Loss - For the six (6) month period ending June 30, 2013 the Company had an increase in other expenses of ($5,650). This increase was due to California State tax franchise fees.

Liquidity - At June 30, 2013, the Company had a cash balance of $85,178, which includes restricted cash of $46,065, compared to June 30, 2012 where the Company had a cash balance of $110,828. This decrease in cash is attributed to general and administrative costs associated with running a public company, as well as an increase in acquisition costs related to the White Wolf prospect, and Lani's share of drilling Well 77-20.

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

Based on current expectations, Lani believes that we are not sufficiently funded beyond July 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 July, 2013. There is an uncertainty as to whether the Company can maintain operations through the third 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.


Consolidated Results of Operations for the Three Months Ended June 30, 2013 Compared to the Three Months Ended June 30, 2012

Expenses from Operations - The Company incurred operating expenses of $326,091 for the three (3) month period ending June 30, 2013; an increase of $298,280 compared to $27,811 for the three (3) month period ending June 30, 2012. The operating expense increase was primarily due to an increase in general and administrative costs.

Other Income/Loss - For the three (3) month period ending June 30, 2013 and 2012 the Company had $0 other income.

Liquidity - At June 30, 2013, the Company had a cash balance of $85,177compared to June 30, 2012 where the Company had a cash balance of $110,828.

Liquidity and Capital Resources

As of June 30, 2013, we had cash and cash equivalents of $85,177, which includes restricted cash of $46,065. We believe this amount is not sufficient to fund our general and administrative costs past July, 2013. We do not currently have the financing in order to carry out our projected 12-month plan of operations. We will rely on external sources of capital in order to continue to fund the Company's general and administrative costs, as well as external sources of capital to fund our capital projects.

Net Cash Used in Operating Activities

Cash used in operating activities in the six months ended June 30, 2013 was $891,776 compared to $67,784 used in operating activities in the six months ended June 30, 2012. The increase in cash used in operating activities was primarily due to a reduction in accounts payable from payment of expenses.

Cash Flows Used In Investing Activities

Net cash provided by investing activities for the six months ended June 30, 2013 was $351,942 compared to cash used in investing activities of $97,880 in the six months ended June 30, 2012. The costs for both periods relate to our oil and gas acquisitions and development.

Cash Flows From Financing Activities

Cash provided by financing activities for the six months ended June 30, 2013 was $20 compared to $45,820 provided in the six months ended June 30, 2012. The $45,820 in financing activities was a result of contributions and distributions from member's and other pre-merger short-term loans


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 June 30, 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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