UNITED STATES
Securities and exchange commission
Washington, D.C. 20549
FORM 10-Q
(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2013
or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _______TO _______
Commission File Number: 333-172896
NORTH AMERICAN OIL & GAS CORP.
(exact name of registrant as specified in its charter)
| Nevada | 98-087028 | |
| (State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) |
56 E. Main St. Suite 202
Ventura, CA 93001
(Address of principal executive offices) (Zip Code)
(805) 643-0385
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | o | Accelerated filer | o |
| Non-accelerated filer | o | Smaller reporting company | x |
| (Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
As of August 9, 2013, there were 60,325,000 shares of registrant’s common stock outstanding.
NORTH AMERICAN OIL & GAS CORP.
Table of Contents
PART I. FINANCIAL INFORMATION
| Item 1. | Financial Statements | 3 | |||
| Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 10 | |||
| Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 14 | |||
| Item 4. | Controls and Procedures | 14 | |||
| PART II. OTHER INFORMATION | |||||
| Item 1. | Legal Proceedings | 15 | |||
| Item 1A. | Risk Factors | 15 | |||
| Item 2. | Unregistered Sales of Securities and Use of Proceeds | 15 | |||
| Item 3. | Defaults Upon Senior Securities | 15 | |||
| Item 4. | Mine Safety Disclosures | 15 | |||
| Item 5. | Other information | 15 | |||
| Item 6. | Exhibits | 16 | |||
| SIGNATURES | 17 | ||||
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| NORTH AMERICAN OIL & GAS CORP. | ||||||||
| (A DEVELOPMENT STAGE COMPANY) | ||||||||
| Condensed Consolidated Balance Sheets | ||||||||
June 30, 2013 | December 31, 2012 | |||||||
| ASSETS | (Unaudited) | |||||||
| Current Assets | ||||||||
| Cash and Cash Equivalents | $ | 39,113 | $ | 578,928 | ||||
| Restricted Cash | 46,065 | 937,067 | ||||||
| Accounts Receivable | 157 | 4,770 | ||||||
| Prepaid Expenses | 1,655 | 4,140 | ||||||
| Total Current Assets | 86,991 | 1,524,905 | ||||||
| Unproved Oil and Gas Properties, Successful Efforts method | 235,909 | 278,754 | ||||||
| Furniture, Fixtures, and Equipment, Net | 5,953 | 4,685 | ||||||
| Deposits | 21,300 | 21,300 | ||||||
| Total Non-current Assets | 263,162 | 304,740 | ||||||
| TOTAL ASSETS | $ | 350,153 | $ | 1,829,645 | ||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||
| Liabilities | ||||||||
| Current Liabilities | ||||||||
| Accounts Payable | $ | 66,763 | $ | 608,550 | ||||
| Accounts Payable - Related Party | 300,000 | 60,000 | ||||||
| Advance from Working Interest Owner | 125,813 | 736,991 | ||||||
| Other Current Liabilities | 86,616 | - | ||||||
| Note Payable - Related party | 50,000 | 50,000 | ||||||
| Total Current Liabilities | 629,192 | 1,455,542 | ||||||
| Long-term Liabilities | ||||||||
| Asset Retirement Obligation | 95,771 | 62,029 | ||||||
| Total Liabilities | 724,965 | 1,517,571 | ||||||
| Commitments and Contingencies | ||||||||
| Shareholders' Equity (Deficit) | ||||||||
Common Stock: $0.001 par value; 200,000,000 shares authorized; 60,325,000(1) shares issued and outstanding and 60,125,000 shares issued and outstanding, respectively | 60,325 | 60,125 | ||||||
| Preferred Stock; 25,000,000 authorized; zero issued | - | - | ||||||
| Additional paid-in capital | 1,010,148 | 654,155 | ||||||
| (Deficit) Accumulated During the Development Stage | (1,445,284 | ) | (402,206 | ) | ||||
| Total Shareholders' Equity (Deficit) | (374,811 | ) | 312,074 | |||||
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY (DEFICIT) | $ | 350,153 | $ | 1,829,645 | ||||
The accompanying notes are an integral part of these unaudited consolidated financial statements
3
NORTH AMERICAN OIL & GAS CORP.
(A DEVELOPMENT STAGE COMPANY)
Condensed Consolidated Statements of Operations
(Unaudited)
| For the Three Months Ended June 30, | For the Six Months Ended June 30, | Cumulative Period from Inception June 20, 2011 Through | ||||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | June 30, 2013 | ||||||||||||||||
| Total Revenue | - | - | - | - | - | |||||||||||||||
| Expenses | ||||||||||||||||||||
| Exploration & Leasehold Costs | 47,662 | 11,476 | 410,202 | 13,697 | 608,636 | |||||||||||||||
| Management and Consulting | 39,980 | 2,000 | 54,980 | 3,000 | 156,754 | |||||||||||||||
| General and Administration | 236,848 | 14,278 | 569,046 | 17,429 | 791,338 | |||||||||||||||
| Depreciation | 39 | 57 | 78 | 57 | 2,005 | |||||||||||||||
| Accretion on Asset Retirement Obligation | 1,562 | - | 3,123 | - | 3,745 | |||||||||||||||
| Total Expenses | 326,091 | 27,811 | 1,037,428 | 34,183 | 1,562,477 | |||||||||||||||
| Other Income (Expense) | ||||||||||||||||||||
| Other Expenses | - | - | 5,650 | - | (6,617 | ) | ||||||||||||||
| Gain on Sale of Oil and Gas Properties | - | - | - | - | 123,476 | |||||||||||||||
| Total Other Income (Expense) | - | - | 5,650 | - | 116,859 | |||||||||||||||
| Net (Loss) | $ | (326,091 | ) | $ | (27,811 | ) | $ | (1,043,078 | ) | $ | (34,183 | ) | $ | (1,445,618 | ) | |||||
| (Loss) per common share | $ | (0.01 | ) | $ | (0.00 | ) | $ | (0.02 | ) | $ | (0.00 | ) | $ | (0.02 | ) | |||||
| Weighted average number of shares outstanding | 60,287,222 | 24,300,000 | 62,206,111 | 24,300,000 | 35,535,400 | |||||||||||||||
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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NORTH AMERICAN OIL & GAS CORP.
(A DEVELOPMENT STAGE COMPANY)
Condensed Consolidated Statements of Cash Flows
For the Six Months Ended June 30, | Cumulative Period from Inception June 20, 2011 through June 30, | |||||||||||
| 2013 | 2012 | 2013 | ||||||||||
| Cash Flows from Operating Activities: | ||||||||||||
| Net (Loss) | $ | (1,043,078 | ) | $ | (34,184 | ) | $ | (1,440,516 | ) | |||
| Adjustments to Reconcile Net (Loss) to Net Cash | ||||||||||||
| (Used in) Operating Activities: | ||||||||||||
| Depreciation expense | 78 | - | 2,005 | |||||||||
| Accretion expense | 3,123 | - | 3,745 | |||||||||
| (Gain) on sale of oil & gas properties | - | - | (125,813 | ) | ||||||||
| Stock based compensation | 356,173 | - | 331,605 | |||||||||
| Changes in Assets and Liabilities: | - | |||||||||||
| (Increase)/Decrease in accounts receivable | 4,613 | - | (157 | ) | ||||||||
| (Increase)/Decrease in prepaids and other assets | 2,484 | - | (22,956 | ) | ||||||||
| Increase/(Decrease) in accrued expenses | 86,616 | (448 | ) | 86,616 | ||||||||
| Increase/(Decrease) in accounts payable | (541,786 | ) | (33,151 | ) | 9,015 | |||||||
| Increase/(Decrease) in accounts payable - related party | 240,000 | - | 300,000 | |||||||||
| Net Cash (Used in) Operating Activities | (891,776 | ) | (67,783 | ) | (772,659 | ) | ||||||
| Cash Flows from Investing Activities: | ||||||||||||
| (Purchase) of oil and gas property | (537,715 | ) | (22,166 | ) | (1,663,999 | ) | ||||||
| Prospect Fees | - | 125,000 | 200,000 | |||||||||
| Proceeds from the sale of oil & gas properties | - | - | - | |||||||||
| (Purchase) of furniture, fixtures and equipment | (1,345 | ) | (4,954 | ) | (7,958 | ) | ||||||
| (Increase) / Decrease in restricted cash | 891,002 | - | (46,065 | ) | ||||||||
| Net Cash Provided by (Used in) Investing Activities | 351,942 | 97,880 | (1,518,022 | ) | ||||||||
| Cash Flows from Financing Activities: | ||||||||||||
| Proceeds from the sale of common stock | 20 | - | 500,100 | |||||||||
| Contributions | - | 50,000 | 213,874 | |||||||||
| (Distributions) | - | (109,180 | ) | (134,180 | ) | |||||||
| Advances From working interest owner | - | - | 1,700,000 | |||||||||
| Proceeds from related party notes | - | 105,000 | 50,000 | |||||||||
| Net Cash Provided by (Used In) Financing Activities | 20 | 45,820 | 2,329,794 | |||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | (539,814 | ) | 75,917 | 39,113 | ||||||||
| Cash and Cash Equivalents at the Beginning of the Period | 578,927 | 34,911 | - | |||||||||
| Cash and Cash Equivalents at the End of the Period | $ | 39,113 | $ | 110,828 | $ | 39,113 | ||||||
| SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTIONS | ||||||||||||
| Recovery of Oil and Gas Property | $ | 75,117 | $ | - | $ | 75,117 | ||||||
| Asset Retirement Obligation | 30,619 | - | $ | 92,026 | ||||||||
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NORTH AMERICAN OIL & GAS CORP.
(A DEVELOPMENT STAGE COMPANY)
Notes To Condensed Consolidated Financial Statements
(Unaudited)
NOTE 1 – THE COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
North American Oil & Gas Corp. (hereinafter referred to as the “Company”) was incorporated in the State of Nevada on April 7, 2010. Since November 16, 2012, the Company has been engaged in the exploration and development of oil and natural gas. The Company is considered a development stage exploration company in accordance with Financial Accounting Standards Board (“FASB”) and Accounting Standards Codification (“ASC”) No. 915, “Development Stage Entities”.
Basis of Presentation
The accompanying unaudited condensed interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and rules of the Securities and Exchange Commission (“SEC”), and should be read in conjunction with the audited consolidated financial statements and notes thereto contained in the Company’s annual report on Form 10-K for the year ended December 31, 2012 filed with the SEC on March 29, 2013. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.
Notes to the consolidated financial statements which would substantially duplicate the disclosure contained in the audited consolidated financial statements as reported in the 2012 annual report on Form 10-K have been omitted.
NOTE 2 – GOING CONCERN
The Company’s financial statements are prepared using accounting principles generally accepted in the United States of America applicable to a going concern, which contemplates the realization of assets and liquidation of liabilities in the normal course of business. The Company has not yet established an ongoing source of revenue sufficient to cover its operating costs, which indicates a substantial doubt of its ability to continue as a going concern. The company accumulated losses of $1,445,284 from Inception through June 30, 2013. The ability of the Company to continue as a going concern is dependent on the Company obtaining adequate capital to fund operating losses until it becomes profitable. If the Company is unable to obtain adequate capital, it could be forced to cease development of operations.
Recoverability of a major portion of the recorded asset amounts shown in the accompanying balance sheet is dependent upon continued operations of the Company, which in turn is dependent upon the Company’s ability to raise additional capital, obtain financing, and succeed in its future operations. If the Company is unable to become profitable, the Company could be forced to discontinue operations.
The financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts
NOTE 3 – RELATED PARTY TRANSACTIONS
The Company entered into a short-term loan with ASPS Energy Investments, Ltd., on September 7, 2012, for the principal sum of $50,000, with interest rate of 3%. The note is payable on September 6, 2013, when the outstanding amount of principal and interest is due in full.
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On November 13, 2012, the Company entered into a Farm-In agreement with Avere Energy Corp (“Avere”), a wholly owned subsidiary of East West Petroleum Corp. According to the provisions of the agreement, Avere is to fund $300,000 for overhead, which was released on an as-needed basis. The Company shall return this funding to Avere from future production revenues or from investments from third parties, minus any realized overhead per the Joint Operating Agreement, whichever comes first. At December 31, 2012 Avere funded $60,000 for overhead, and additional funding of $240,000 from January 1, 2013 through the quarter ending June 30, 2013, bringing the total funded to $300,000.
Additionally, Avere has provided $1,300,000 to finance the drilling of Well 77-20 in exchange for a 25% working interest in the Tejon Extension. Well 77-20 has been drilled, and is currently shut in while reviewing additional testing possibilities.
Through the Farm-In, Avere agreed to fund $347,500 in total to acquire the White Wolf Prospect in exchange for a 50% working interest. As of June 30, 2013, Lani through an aggressive acquisition program secured 4,663 gross acres, 2,239 net acres, at an average cost per acre of $135.18. The total costs for the White Wolf leasing acquisition program to through June 30, 2013 is $382,907, with $120,051 expended for delay rents, and $262,856 expended in brokerage fees . Per the farm-in Lani was to secure an additional 483 net acres at 100% Lani cost. Through June 30, 2013 $91,806 of White Wolf acquisition cost has been capitalized on NAMOGs balance sheet.
On February 1, 2013, the Company entered into a consulting contract with a Board Director, Cosimo Damiano. The consulting contract is for twelve months at a rate of $5,000 per month, and covers a variety of consulting activities in the management and operations of the Company. For the six (6) month period ending June 30, 2013 the Company incurred consulting fees totaling $15,000, $10,000 of which is included in accounts payable as of June 30, 2013, with nine (9) months remaining on this contract as of June 30, 2013.
On April 1, 2013 Donald Boyd, Operations Manager, and Robert Skerry Hoar, Managing Geologist, agreed to termination of their services as full time employees, and signed Consulting Agreement contracts with the Company. The contracts stipulate $5,000 per month fixed compensation for consulting services in the ongoing operations of Lani.
NOTE 4 – ASSET RETIREMENT OBLIGATION
The following table summarizes the change in the asset retirement obligation (“ARO”) for six months ended June 30, 2013 and 2012.
| For Six Months Ended | ||||||||
| June 30, 2013 | June 30, 2012 | |||||||
| (unaudited) | (unaudited) | |||||||
| Asset retirement obligation, beginning of period | $ | 62,029 | $ | - | ||||
| Liabilities incurred from new drilling | - | 61,407 | ||||||
| Revisions of estimated cash flows | 30,619 | |||||||
| Accretion expenses | 3,123 | 622 | ||||||
| Asset retirement obligation, end of period | $ | 95,771 | $ | 62,029 | ||||
The ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. The ARO is calculated for Well 77-20, based on a cost to plug and abandon the well at $150,000. The ARO has been calculated using the Company’s share at 75% of the working interest in the leased property.
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NOTE 5 – STOCK OPTIONS
The Company awarded Linda Gassaway, Chief Financial Officer, 500,000 shares of stock options on April 1, 2013. The restricted stock options were offered at an exercise price of $.80 per share, and will vest one year from date of grant.
The fair value of the option grants were estimated on the date of the grant using the Black-Scholes option-pricing model with the following weighted average assumptions: expected volatility of 665%, risk free interest rate of 0.78%; and expected term of five and one half years.
A summary of the Company’s stock option activity and related information is as follows:
| Number of Shares | Weighted-Average Remaining Life (in years) | Aggregate Intrinsic Value | Weighted Average Exercise Price | |||||||||||||
| Outstanding at January 1, 2013 | - | - | - | |||||||||||||
Granted(1) | 850,000 | 9.76 | $ | 0.76 | ||||||||||||
| Exercised | - | - | - | |||||||||||||
| Cancelled/Expired | - | - | - | |||||||||||||
| Outstanding at June 30, 2013 | 850,000 | 9.76 | $ | 0.76 | ||||||||||||
| Vested and Exercisable at June 30, 2013 | 350,000 | $ | 0.70 | |||||||||||||
(1) Includes 350,000 options granted to PacSeis February 18, 2013, and options granted to Linda Gassaway, Chief Financial Officer of NAMG April 1, 2013
The following table presents the weighted-average assumptions used to estimate the fair values of the stock options granted in the period presented:
| Six Months Ended June 30, 2013 | Year Ended December 31, 2012 | |||||||
| (unaudited) | ||||||||
Risk-free interest rate(1) | 0.78 | % | - | |||||
Expected life (in years)(2) | 5.25 | - | ||||||
Expected volatility(3) | 255.02 | % | - | |||||
| Dividend yield | - | - | ||||||
| (1) The Risk Free Rate is a 5 Year Treasury rate. |
| (2) The expected life (in years) is based on the simplified method: Expected term = ((vesting term + original contractual term)/2). |
| (3) The expected volatility is based on the volatility weighted average of stock options |
8
During the six months ended June 30, 2013, the Company recorded stock-based compensation of $356,173 and $61,492, respectively, as general and administrative expenses, and G & G Services. At June 30, 2013 the weighted average remaining life of the stock options is 5.25 years. The unamortized amount of stock-based compensation at June 30, 2013 was $276,714. This cost is expected to be recognized over the next three fiscal quarters.
NOTE 6 – SUBSEQUENT EVENTS
On July 31, 2013, Lani LLC and Avere Energy Corp. entered into an agreement wherein Avere/EWP will advance to Solimar Energy LLC, by wire transfer, Lani/NAOG’s (“NAMG”) $125,000 to acquire an additional 18.75% interest of 100% right, title and interest in the Tejon Main prospect. For consideration of this payment on behalf of Lani, Lani will pay Avere/EWP $140,000 within five days following (a) the closing of a private or public offering of its securities, (b) from any other fund raising or farm out initiative, or (c) revenue from any Lani/NAMG production or asset sales, whichever comes first. In the event Solimar relinquishes its retained interest in the Tejon Main area leases pursuant to the terms of the JOA, the interest relinquished shall be acquired by Lani/NAMG 40%, Avere/EWP 60%. In the event Lani is unable to continue as a going concern and operator, Lani will assign Avere its 40% interest in the Tejon Main area at no cost to Avere.
Effective July 31, 2013 Lani, Avere Energy Corp. and Solimar Energy LLC amended the Joint Operating Agreement of the Tejon Main Lease area (effective November 13, 2013) to the follows:
| 1) | Removal of Solimar Energy LLC and operators, |
| 2) | Lani assumes all rights as operator for deep and ‘shallow’ depths, |
| 3) | As of the date of the amended JOA, Avere and Solimar shall be non-operators under the JOA, and, |
| 4) | Amending Article VIII, Section D, to add a new paragraph agreeing that all parties are prohibited from farming out, selling or otherwise divesting less than 10% of 100% of their rights title and interest in the leases prior to a discovery well being drilled on the leases. |
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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.
10
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.
11
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
12
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.
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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.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Not required under Regulation S-K for “smaller reporting companies.”
Item 4. Controls and Procedures. Evaluation of disclosure controls and procedures.
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this Quarterly Report on Form 10-Q. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.
Based on our evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are not designed at a reasonable assurance level and are not effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in internal control over financial reporting.
There were moderate changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2013, although these have not materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
We are currently not a party to any material legal proceedings or claims.
Item 1A. Risk Factors.
Not required under Regulation S-K for “smaller reporting companies.”
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information.
None.
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Item 6. Exhibits.
| 10.01 | Agreement Between Lani LLC and Avere Energy Corp. July 31, 2013 |
| 10.02 | Amendment to Joint Operating Agreement |
| 10.03 | Agreement to purchase & Sell Leases Tejon Area |
| 31.1 | Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| 31.2 | Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| 32.1 | Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| 101.INS ** | XBRL Instance Document | |
| 101.SCH ** | XBRL Taxonomy Extension Schema Document | |
| 101.CAL ** | XBRL Taxonomy Extension Calculation Linkbase Document | |
| 101.DEF ** | XBRL Taxonomy Extension Definition Linkbase Document | |
| 101.LAB ** | XBRL Taxonomy Extension Label Linkbase Document | |
| 101.PRE ** | XBRL Taxonomy Extension Presentation Linkbase Document |
** XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| NORTH AMERICAN OIL & GAS CORP. | |||
| Date: August 12, 2013 | By: | /s/ Robert Rosenthal | |
| Robert Rosenthal | |||
| Chief Executive Officer | |||
| Date: August 12, 2013 | By: | /s/ Linda Gassaway | |
| Linda Gassaway | |||
| Chief Financial Officer |
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