Attached files
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2013
or
[ ] 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: 333-178251
NORTH TEXAS ENERGY, INC.
(Exact name of registrant as specified in its charter)
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NEVADA
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27-4556048
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State or other jurisdiction of incorporation or organization
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(I.R.S. Employer Identification Number)
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5057 KELLER SPRINGS ROAD, SUITE 300, ADDISON, TEXAS
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75001 |
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(Address of principal executive offices)
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(Zip Code)
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Registrant's telephone number, including area code:
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469-718-5572
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Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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COMMON
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NONE
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Securities registered pursuant to Section 12(g) of the Act:
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. [ ] Yes [X] No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. [ ] Yes [X] No
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 report), and (2) has been subject to such filing requirements for the past 90 days. [X] Yes [ ] No
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 to submit and post such files. [X] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.[ ]
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 "small reporting company" in Rule 12b-2 of the Exchange Act.
| Large accelerated filer [ ] | Accelerated filer [ ] |
| Non-accelerated filer [ ] | Smaller reporting company [X] |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): [ ] Yes [X] No
As of April 14, 2014, 6,239,515 shares of common stock, $0.00001 par value per share, were outstanding.
PART I
Item 1. Business.
Business Overview and Capital Fund Raising
North Texas Energy, Inc. (“NTE”, “the Company”, “we”) is a non-traditional producer of crude oil. The Company acquires oil and gas leases with non-functioning wells and uses Enhanced Oil Recovery Methods (“EOR”) to bring wells back into production. The Company currently holds oil and gas leases in Milam County, Texas of which it holds one-hundred percent of the working interest. In order to execute its business plan to recover the oil and gas reserves on its leased property, the Company prepared and filed an S-1 Registration Statement for the sale of two million shares of its common stock. The price of the common shares was set at $2.00 per share. The registration statement became effective on March 29, 2013. The sale of the common shares was and is being conducted without an underwriter.
Since the Company's S-1 Registration Statement became effective on March 29, 2013, the Company by and through its CEO, Kevin Jones, beginning in June 2013 and through December 31, 2013, issued 346,765 shares registered in the stock offering. The shares were sold at the offering price of $2.00 per share yielding to the Company an equity capital infusion of $693,530. The Company also issued 1,500 shares of restricted stock for cash at $1.00 per share to a private party. The total stock sales combined netted the Company $695,030 in capital infusion. The Company continues to issue shares of its common stock in accordance with the registration statement and will continue until all of the 2,000,000 shares are sold.
NTE is an Enhanced Oil Recovery (“EOR”) company. EOR is a term used to describe a variety of methods by which oil reserves are recovered from existing oil fields that were not completely exhausted using standard methods. We are not an “exploration company” in the sense that our business and our methods do not involve an attempt to explore for new oil reserves but rather to exploit existing known oil fields using other than “standard” recovery methods. In simplified terms, the "standard" methods of producing oil and natural gas from its location in natural reservoirs in the earth is to drill a relief (well) into the reservoir and allow the reservoir's crude oil to surface because of the natural pressure that exists in the reservoir structure underground. Once a well is finished and well casing is in place, the oil and natural gas will surface under its own pressure or with a small amount of suction introduced into the well. As the oil surfaces so does the natural gas. The gas and oil are separated and stored or delivered directly to market.
Enhanced Oil Recovery methods identify the process(s) by which substantial amounts of oil and gas that remain in a field reservoir, after standard recovery methods are exhausted, can be recovered using a variety of methods of enhancing the natural pressure in a reservoir or using some other method to release additional trapped oil in the reservoir. EOR allows for the recovery of significantly more oil from the same field by introducing additional pressure or other geological changes in the reservoir. The original well, well casing and well head equipment, are used in the process.
NTE initially uses an EOR method called "microbial injection" to induce pressure in its oil field reservoirs and allow for the remaining oil reserves to be recovered. Microbial injection is the process by which nutrients or compounds are injected into an oil field to allow for the natural enhancement of the movement and release of the oil out of the reserve. According to the U.S. Department of Energy Fossil Energy report on Oil and Natural Technologies “Enhanced Oil Recovery” Conventional primary and secondary recovery operations often leave two-thirds of the oil in the reservoir at the time of abandonment. Enhanced oil recovery methods have the potential for recovering much of the remaining oil." - U.S. DOE. The concept is to use natural environmental reactions to improve the recovery of oil trapped in porous media in the reservoir or without sufficient pressure to allow the oil and gas to be expressed normally from the reservoir to above ground. In each different oil field, the method by which EOR can be successful is dependent on the oil field and reservoir structure. The uniqueness of each field may involve unique EOR methods which can be any combination of methods involving the use of expertise in the disciplines of geology, chemistry, and microbiology as well as fluid mechanics and a variety of engineering applications.
Corporate History and Background
The Company was organized in Nevada in January 2011. We are a combination of two companies, each originally founded for the same purpose. The predecessor to NTE is Remington Oil & Gas, Inc., a Nevada corporation, and its predecessor is Remington Oil & Gas LLC., a Texas Limited Liability Company. During 2009, Remington Oil & Gas, LLC acquired oil field leases in North Texas, in Upshur country. In January 2010, Remington Oil & Gas, Inc. acquired all of the outstanding ownership interests of Remington Oil & Gas, LLC. In the process, Remington Oil & Gas, Inc. acquired the oil and gas leases in North Texas that had been previously assigned to Remington Oil & Gas, LLC. Effective in January 2011, North Texas Energy, Inc. acquired Remington Oil & Gas, Inc. through a Purchase and Sale Agreement. The Purchase and Sale Agreement transferred title of Remington’s well-head equipment to North Texas Energy, Inc. and provided for the acquisition of all of the outstanding shares of Remington Oil & Gas, Inc. by North Texas Energy, Inc. in a one-for-one share exchange.
1
Properties
Oil and Gas Properties, Wells, Operations and Acreage
The following table sets forth information relating to our principal properties as of December 31, 2013:
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2013 Net Production
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Net
acreage
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Average
working
interest %
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Gross
producing
wells
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Net proved
reserves
(bbls)
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Oil
(bbls)
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Natural Gas
(mcf)
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|||||||||||||||||||
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Milam County, Texas
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126
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100
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%
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6
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795,999
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120
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-
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Reserve Estimates-Oil and Gas Reserves
As an oil and gas producing entity the Company is required to prepare and file an estimate of its total proved oil and gas reserves at the end of its fiscal year. In that regard the Company has employed a third party certified petroleum engineer to prepare an estimate of it reserves in accordance with Securities and Exchange Commission (“SEC”) rules and regulations.
The following tables sets forth, as of December 31, 2013, our estimated net proved oil reserves, and the estimated present value (discounted at an annual rate of 10%) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves, each prepared in accordance with assumptions prescribed by the Securities and Exchange Commission (“SEC”).
The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent. PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carry forwards and other factors. We believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
2
These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.
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Oil
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(bbls)
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Reserve category
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Proved Developed
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Milam County, Texas
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365,319 | |||
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Proved Undeveloped
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Milam County, Texas
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430,680 | |||
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Total Proved Reserves
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795,999 | |||
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Proved Developed
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Proved Undeveloped
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Total Proved
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PV-10(1)
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$
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17,375,987
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$
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21,239,187
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$
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38,615,174
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Standardized measure (2)
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$
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11,034,826
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$
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12,020,183
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$
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23,055,009
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(1)
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In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2013. For purposes of determining prices, we used the unweighted arithmetical average of the prices on the first day of each month within the 12-month period ended December 31, 2013. The average prices utilized for purposes of estimating our proved reserves were $97.61 per barrel of oil for our properties. The prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.
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(2)
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The Standardized Measure differs from PV-10 only in that the Standardized Measure reflects estimated future income taxes.
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Due to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
3
Oil and Gas Production, Production Prices and Production Costs
The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sales of gas and oil for each of the three years ended December 31, 2013:
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Year Ended December 31,
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2013
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2012
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2011
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Net Production:
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Oil (Bbls):
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Milam County, Texas
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120
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-
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-
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Average sales price:
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Oil ($ per Bbl)
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||||||||||||
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Milam County, Texas *
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-
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-
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-
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Average production costs ($ per Bbl):
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Milam County, Texas
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- |
-
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-
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*As of December 31, 2013, the Company has not sold any oil and gas products that it has produced.
Drilling and other Exploratory and Development Activities
The Company is an oil and gas producing company that currently has no exploration activities. The Company is solely an oil and gas producing company that attempts to produce crude oil from existing wells on its leased properties and does no exploration or exploratory activity.
4
Present Activities
The Company plans to drill 8 new wells on its current leases in 2014 and is in the process of refurbishing a total of 25 shut-in wells on its leased oil and gas properties. As of December 31, 2013, the Company had refurbished a total of six wells that it has on its Balch Lease. Late in December of 2013, those six wells began producing small amounts of crude oil.
Delivery Commitments
The Company has no contractual commitments to deliver or sell any oil or gas production from its leased oil and gas properties as of the date of this report or at December 31, 2013.
Operations
The Company began the year with oil and gas leases secured in both Milam and Upshur County Texas. In Milam County (Balch Lease) the Company had eleven installed wells that had been shut-in because the wells were producing large amounts of paraffin with the oil they produced. The Company's production plan was to introduce a process called "Microbial Enhanced Oil Recovery" or MEOR. This process introduces microbial materials into the well geology enhancing the production of oil that previously was prevented by the status of the geological structure. We introduced the technology in six wells on the Balch lease that we planned to bring into production. The outcome was that the Microbial Enhancement thinned the paraffin significantly enough to allow oil production to begin again in six wells as of December 31, 2013
Once the MEOR concept was proven, we began the development of the lease property including the installation of new storage tanks, land clearing, fencing, electrical power, flow lines, pumping equipment, oil separation and collection equipment and improved down-hole production equipment to further enhance production. So, by December 31, 2013 we had proved our MEOR concept, installed a production infrastructure and brought six wells into production.
In the month of December 2013 we produced approximately 120 barrels of oil from the refurbished wells on the Balch Lease. As of this reporting date, the Company had a total of nine producing wells on its Balch Lease. The Company plans to further its development of its oil and gas leased properties starting from 2014 by introducing the MEOR technology into wells and the geology on leases it has acquired after December 31, 3013.
Development Plans
Particularly plans are to bring all of the wells on all of the leased property within 2 years. The Company has a total of 25 wells in place on a total of 336 gross well acres. The Company acquired oil and gas leases adjacent to the Balch Lease described as the "McGregor Lease" in July of 2013. The McGregor lease totals 35 gross well acres and has three installed wells. All of the McGregor wells will be treated with the MEOR technology, refurbished and brought on-line in the first half of 2014. The Company acquired additional leases adjacent to the Balch Lease after December 31, 2013. Those leases are the "Cromwell" and "Hicks" leases and contain 123 and 87 gross well acres with 6 and 5 installed wells, respectively. The Company is currently treating and bringing on-line wells on those properties. The Company plans on having all 25 of its installed wells treated and producing within 2 years.
5
Employees
As of May 1, 2014, we have 1 full-time employee and 1 part-time employee. The employees are not covered by a collective bargaining agreement, and we do not anticipate that any of our future employees will be covered by such agreements. We engage consultants on an as-needed basis for operation.
Regulatory Matters
The oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments. Compliance with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. The failure to comply with the statutes, rules and regulations could result in the imposition of fines and penalties and the suspension or cessation of operations in affected areas. We routinely obtain permits for our facilities and operations in accordance with the applicable laws and regulations on an ongoing basis. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations.
The ultimate financial impact of environmental laws and regulations is neither clearly known nor easily determined as new standards are enacted and new interpretations of existing standards are rendered. Environmental laws and regulations are expected to have an increasing impact on our operations. In addition, any non-compliance with such laws could subject us to material administrative, civil or criminal penalties, or other liabilities. Potential permitting costs are variable and directly associated with the type of facility and its geographic location.
Item 1a. Risk Factors.
As a smaller reporting Company the company is not required to report on Risk Factors in its Annual Report to Shareholders.
Item 1b. Un-Resolved Staff Comments.
The Company has no disclosures responsive to this item 1b.
The Company has oil and gas leases in Milam County, Texas (Balch Lease) on which it is producing crude oil. Additionally the Company has an oil and gas lease contiguous to its Balch Lease called the "McGregor Lease". As of this report date the Company has 11 wells on its Balch Lease (including 6 operating wells that began producing crude oil in December 2013). The Company has 3 wells on its McGregor Lease that it plans to refurbish and bring into production before 2015. The Balch Lease and the McGregor leases cover 91 and 35 well acres respectively for a total of 126 well acres under the Company’s control.
6
On December 18, 2013 the Company's oil and gas leases in Upshur County, Texas expired and it does not intend to pursue renewing those leases. However, the Company does intend to pursue leases contiguous to its currently held leases in Milam County. In that regard, the Company has taken a one-time write down of its un-proved properties in the amount of $1,238,887 for the year ended December 31, 2013.
In its newly issued Petroleum Engineer's Report dated December 31, 2013 the Company is reporting; Proved Developed and Producing reserves of approximately 365,319 stock tank barrels, Proved Un-Developed Non-Producing reserves of approximately 430,680 stock tank barrels; Total Proved Reserves of approximately 795,999.
Item 3. Legal Proceedings.
The Company is not a party to nor is it aware of any significant legal proceeding that would negatively affect its operation or financial condition.
Item 4. Mine Safety Disclosures
The company has no disclosures responsive to this item 4.
7
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters
Market Information
The Company's registration statement of its common stock for sale became effective on March 29, 2013. The Company is not employing an underwriter to assist it in the sale of the common shares. The shares are being sold by and through the Company's CEO, Kevin Jones.
The Company has sold and issued common stock to private parties totaling 346,765 common shares of registered stock and 1,500 shares of restricted shares for a total of $695,030 as of this report date. All of the sales were made on the efforts of the Company's CEO, Kevin Jones, with private parties. There is no ready public trading market for the Company's common shares. Even though the shares sold are not restricted and are "free trading shares", the Company has not listed its shares for sale on any stock exchange as of the date of this report. So, there is no method of trading electronically for the shares. However, the Company intends to seek a market maker and file the necessary documents to meet the necessary requirements to obtain a listing and develop a public market for its common stock as well as make arrangements for electronic trading of the shares. Until that time no public market for trading the Company's stock exists.
Holders
As of May 1, 2014, there were approximately 127 shareholders of record of our common stock.
Dividends
No dividends were paid during calendar years 2012 or 2013. The payment of future cash dividends will depend upon, among other things, our financial condition, funds from operations, the level of our capital and development expenditures, our future business prospects, contractual restrictions and any other factors considered relevant.
Recent sales of unregistered securities
During the year ended December 31, 2013, the Company sold 1,500 shares to an individual for $1,500 cash.
8
Item 6. Selected Financial Data.
As a Smaller Reporting Company the Company is not required to make disclosures related to this item 6.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Overview
North Texas Energy, Inc. is in its exploration stage. The results of operations show how capital intensive and profitless the oil and gas production business is at start up. The progress so far has been limited by severely limited access to working capital. One of the most important economic factors in the U.S economy is the successful exploration and production of crude oil and natural gas. North Texas Energy, Inc. is committing its business and resources to the production of crude oil and natural gas that remains in geological formations in oil fields that have been previously explored and have produced significant amounts of crude oil already. Data and research produced by the Department of Energy indicates that additional significant reserves of crude oil and natural gas remain in fields that were once productive in the past. In recent years and with the price of crude oil steady at about seventy-four dollars per barrel (since 2008), new production methods have emerged as cost-effective in recovering the substantial remaining oil that has not been recovered using standard methods. North Texas Energy, Inc. entered into the business of recovering oil in previously drilled and producing fields in 2009 by acquiring oil and natural gas leases in north Texas. NTE’s predecessor operated in year 2010 for a short period of time. During that time, the Company had access to private capital from sales of common stock to shareholders. The capital from investment by private shareholders was limited and sales were terminated late in 2010. The funds invested at that time were used mainly to begin the process of refurbishing wells and preparing well head installations for re-use. The short operations history shows that without on-going sources of working capital, the initial cost of getting wells and drill bores functional to begin the process of recovering oil that remains in the geological formation will not be met and significant delays in recovering the remaining oil would occur.
Results of Operations
For the year ended December 31, 2013, the Company had a net loss of $1,567,380 compared to a net loss of $20,135 for the year ended December 31, 2012. The significant portion of the loss comes from the impairment expense taken as a result of the Company's lease expirations on its unproved oil and gas properties. This loss was represented by a non-cash one time charge to record the loss of the properties by virtue of the lease expiration and totaled $1,238,887.
Revenues
We have had no revenues since our inception.
Operating expenses
For the year ended December 31, 2013 the Company had an operating expenses of $1,566,694 compared to $20,135 for the year ended December 31, 2012. Of the operating expenses, the most significant were those related to the impairment of oil and gas properties of $1,238,887 as discussed above. The increase of operating expenses was also attributable to the increase of legal and professional fees by $136,954 and the increase of general and administrative expenses by $163,753. The increase of the legal and professional fees was related mostly to the sale of the Company's common shares and the on-going auditing and reporting requirements. The increase of the general and administrative expense was mainly due to the increase of general liability insurance expenses of $43,429 for the year ended December 31, 2013. The Company has changed its insurance carriers and expects the expense to be approximately $7,000 for the year ended December 31, 2014. The increase of general and administrative expense was also attributable to the increase of compensation expense of $39,100, travel and other general expenses.
9
Liquidity
The Company began selling its common shares in accordance with its Registration Statement which became effective on March 29, 2013. On March 29, 2014, the Company filed a revision of its Prospectus that relates to the common stock sales extending the time past the original one year sales period. The Company will continue to sell shares as allowed and use those funds for the further development of its oil and gas properties. The Company believes that it can continue to sell its common stock and use those funds as well as the funds it generates from crude oil production to continue its operations.
The Company has no immediate sources of debt or equity funding that is not related to the offering of its shares. The Company believes it can avoid accumulating debt or using other non-traditional forms of financing to provide liquidity.
At December 31, 2013, our cash and cash equivalents balance was $50,924.
Net cash used in operating activities was $298,119 for the year ended December 31, 2013, compared to $8,603 for the year ended December 31, 2012. The increase was mainly due to increase of payments for legal and professional services, compensation to its officer, insurance policy, as well as other general operating expenses.
Net cash used in investing activities was $364,338 for the year ended December 31, 2013, compared to $0 for the year ended December 31, 2012. The Company had expenditures related to the operation permit and the investment in the infrastructure of its oil and gas properties during 2013.
Net cash provided by financing activities for the year ended December 31, 2013 was $713,381 compared to $8,603 for the year ended December 31, 2012. During the year ended December 31, 2013, the Company received $695,030 proceeds from sale of common stock and $18,351 from capital contribution of its chief executive officer. During the year ended December 31, 2013, the Company received $8,603 from capital contribution of its chief executive officer.
Without additional investment capital from shareholders or other sources, the Company has no short term source of liquidity. In order to bring wells on-line and produce crude oil to bring to market, significant amounts of working capital will be needed to continue. Accordingly, the Company plans to systematically bring wells on-line that have the greatest initial production possibility as capital is available. The Company’s illiquid financial position could cause it to not be able to start producing oil in the near future unless working capital from the offering or some other source of short term liquidity is developed.
Management does not believe that the Company’s current capital resources will be sufficient to fund its operating activity and other capital resource demands during the next year. Our ability to continue as a going concern is contingent upon our ability to obtain capital through the sale of equity or issuance of debt, and ultimately attaining profitable operations. There is no assurance that we will be able to successfully complete any one of these activities.
The Company began producing crude oil in small quantities in December 2013 and had crude oil in its storage tanks at December 31, 2013 with an approximately sales value of $11,780 (valued at $98.17 per barrel). That value is based on the daily price of West Texas Intermediate Crude Oil on December 31, 2013. Subsequent to December 31, 2013, the Company has sold that oil and is now producing more in small quantities from its producing wells on the Balch Lease.
In 2014 the Company plans to complete the necessary technology treatments (MEOR) and refurbishments to a total of 25 installed wells. Those would include: 11 total wells on its Balch Lease, 3 wells on its McGregor Lease, 6 wells on its Cromwell Lease and 5 wells on its Hicks lease.
10
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements or guarantees of third party obligations at December 31, 2013.
Critical Accounting Policies
The following describes the critical accounting policies used in reporting our financial condition and results of operations. In some cases, accounting standards allow more than one alternative accounting method for reporting. Such is the case with accounting for oil and gas activities described below. In those cases, our reported results of operations would be different should we employ an alternative accounting method.
Oil and Gas Properties
The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs for unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping the wells and any internal costs that are directly related to acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or other disposition of oil and gas properties are generally treated as a reduction in the capitalized costs of oil and gas properties, unless the impact of such a reduction would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.
The Company categorizes its full cost pools as costs subject to amortization and costs not being amortized. The sum of net capitalized costs subject to amortization, including estimated future development and abandonment costs, are amortized using the unit-of-production method.
Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the costs subject to amortization.
Recent Accounting Pronouncements
The Company has reviewed recently issued accounting standards, none of which are expected to have a material impact on the Company’s financial position or results of operations.
.
11
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
North Texas Energy, Inc.
(An exploration stage company)
Addison, Texas
We have audited the accompanying consolidated balance sheets of North Texas Energy, Inc. (an exploration stage company) as of December 31, 2013 and 2012, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years then ended, and the period from January 12, 2011 (Inception) to December 31, 2013. North Texas Energy, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of North Texas Energy, Inc. as of December 31, 2013 and 2012, and the results of its operations and its cash flows for the periods described above in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming that North Texas Energy, Inc. will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, North Texas Energy, Inc. has suffered losses from operations and has not secured sufficient funding for its operations. These factors raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ GBH CPAs, PC
GBH CPAs, PC
www.gbhcpas.com
Houston, Texas
May 2, 2014
12
|
NORTH TEXAS ENERGY, INC.
|
||||||||
|
(AN EXPLORATION STAGE COMPANY)
|
||||||||
|
CONSOLIDATED BALANCE SHEETS
|
||||||||
|
December 31,
|
December 31,
|
|||||||
|
2013
|
2012
|
|||||||
|
Assets
|
||||||||
|
Current assets
|
||||||||
|
Cash
|
$ | 50,924 | $ | - | ||||
|
Inventory
|
1,013 | - | ||||||
|
Total current assets
|
51,937 | - | ||||||
|
Oil and gas properties, full cost method
|
||||||||
|
Costs subject to amortization
|
1,147,903 | - | ||||||
|
Costs not being amortized
|
- | 1,987,657 | ||||||
|
Accumulated depletion, depreciation, amortization and impariment
|
(313 | ) | - | |||||
|
Total
|
1,147,590 | 1,987,657 | ||||||
|
Total assets
|
$ | 1,199,527 | $ | 1,987,657 | ||||
|
Liabilities and shareholders' equity
|
||||||||
|
Current liabilities
|
||||||||
|
Accounts payable and accrued liabilities
|
$ | 123,050 | $ | 28,316 | ||||
|
Accrued lease liabilities
|
65,881 | 65,881 | ||||||
|
Current liabilities
|
188,931 | 94,197 | ||||||
|
Asset retirement obligations
|
25,844 | 54,709 | ||||||
|
Total liabilities
|
214,775 | 148,906 | ||||||
|
Commitments and contingencies
|
||||||||
|
Shareholders' equity
|
||||||||
|
Common stock, $0.00001 par value, 100,000,000 shares authorized, 6,179,265 and 5,831,000 shares issued, respectively
|
62 | 58 | ||||||
|
Additional paid-in capital
|
2,410,510 | 1,697,133 | ||||||
|
Earnings (deficit) accumulated during exploration stage
|
(1,425,820 | ) | 141,560 | |||||
|
Total shareholders' equity
|
984,752 | 1,838,751 | ||||||
|
Total liabilities and shareholders' equity
|
$ | 1,199,527 | $ | 1,987,657 | ||||
See notes to the consolidated financial statements.
13
|
NORTH TEXAS ENERGY, INC.
|
||||||||||||
|
(AN EXPLORATION STAGE COMPANY)
|
||||||||||||
|
CONSOLIDATED STATEMENTS OF OPERATIONS
|
||||||||||||
| January 12, | ||||||||||||
| 2011 | ||||||||||||
| (Inception) | ||||||||||||
|
For the Year Ended
|
Through
|
|||||||||||
|
December 31,
|
December 31,
|
|||||||||||
|
2013
|
2012
|
2013
|
||||||||||
|
Revenues
|
$ | - | $ | - | $ | - | ||||||
|
Operating expenses:
|
||||||||||||
|
Depletion and accretion
|
12,381 | 5,416 | 20,554 | |||||||||
|
Impairment of oil and gas properties
|
1,238,887 | - | 1,238,887 | |||||||||
|
Legal and professional fees
|
145,204 | 8,250 | 174,454 | |||||||||
|
General and administrative expenses
|
170,222 | 6,469 | 204,479 | |||||||||
|
Total operating expenses
|
1,566,694 | 20,135 | 1,638,374 | |||||||||
|
Net operating loss
|
(1,566,694 | ) | (20,135 | ) | (1,638,374 | ) | ||||||
|
Other income (expense):
|
||||||||||||
|
Interest expense
|
(686 | ) | - | (686 | ) | |||||||
|
Bargain purchase gain
|
- | - | 213,240 | |||||||||
|
Total other income (expense)
|
(686 | ) | - | 212,554 | ||||||||
|
Net loss
|
$ | (1,567,380 | ) | $ | (20,135 | ) | $ | (1,425,820 | ) | |||
|
Basic and diluted loss per common share
|
$ | (0.26 | ) | $ | (0.00 | ) | ||||||
|
Weighted average number of common shares outstanding - basic and diluted
|
$ | 5,976,117 | 5,831,000 | |||||||||
See notes to the consolidated financial statements.
14
|
NORTH TEXAS ENERGY, INC.
|
||||||||||||||||||||
|
(AN EXPLORATION STAGE COMPANY)
|
||||||||||||||||||||
|
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
|
||||||||||||||||||||
|
Earnings (Deficit)
|
||||||||||||||||||||
|
Common Stock
|
Additional
|
Accumulated During
|
Total Shareholders'
|
|||||||||||||||||
|
Shares
|
Amount
|
Paid-In Capital
|
Exploration Stage
|
Equity
|
||||||||||||||||
|
Balance, January 12, 2011 (Inception)
|
- | $ | - | $ | - | $ | - | $ | - | |||||||||||
|
Issuance of founder's shares
|
5,000,000 | 50 | - | - | 50 | |||||||||||||||
|
Capital contribution
|
- | - | 26,538 | - | 26,538 | |||||||||||||||
|
Acquisition of Remington Oil & Gas, Inc.
|
831,000 | 8 | 1,661,992 | - | 1,662,000 | |||||||||||||||
|
Net income
|
- | - | - | 161,695 | 161,695 | |||||||||||||||
|
Balance, December 31,2011
|
5,831,000 | 58 | 1,688,530 | 161,695 | 1,850,283 | |||||||||||||||
|
Capital contribution
|
- | - | 8,603 | - | 8,603 | |||||||||||||||
|
Net loss
|
- | - | - | (20,135 | ) | (20,135 | ) | |||||||||||||
|
Balance, December 31, 2012
|
5,831,000 | 58 | 1,697,133 | 141,560 | 1,838,751 | |||||||||||||||
|
Capital contribution
|
- | - | 18,351 | - | 18,351 | |||||||||||||||
|
Issuance of common stock for cash
|
348,265 | 4 | 695,026 | - | 695,030 | |||||||||||||||
|
Net loss
|
- | - | - | (1,567,380 | ) | (1,567,380 | ) | |||||||||||||
|
Balance, December 31, 2013
|
6,179,265 | $ | 62 | $ | 2,410,510 | $ | (1,425,820 | ) | $ | 984,752 | ||||||||||
See notes to the consolidated financial statements.
15
|
NORTH TEXAS ENERGY, INC.
|
||||||||||||
|
(AN EXPLORATION STAGE COMPANY)
|
||||||||||||
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
||||||||||||
|
For the Year Ended
|
January 12, 2011
|
|||||||||||
|
December 31,
|
(Inception) Through
|
|||||||||||
|
2013
|
2012
|
December 31, 2013
|
||||||||||
|
Cash Flows From Operating Activities:
|
||||||||||||
|
Net loss
|
$ | (1,567,380 | ) | $ | (20,135 | ) | $ | (1,425,820 | ) | |||
|
Adjustments to reconcile net loss to net cash
|
||||||||||||
|
from operating activities:
|
||||||||||||
|
Share-based compensation
|
- | - | 50 | |||||||||
|
Depletion, accretion and impairment expense
|
1,251,581 | 5,416 | 1,259,754 | |||||||||
|
Bargain purchase gain
|
- | - | (213,240 | ) | ||||||||
|
Changes in operating assets and liabilities:
|
||||||||||||
|
Inventory
|
(1,013 | ) | - | (1,013 | ) | |||||||
|
Accounts payable and accrued liabilities
|
18,693 | 6,116 | 47,009 | |||||||||
|
Net Cash Used in Operating Activities
|
(298,119 | ) | (8,603 | ) | (333,260 | ) | ||||||
|
Cash Flows From Investing Activities:
|
||||||||||||
|
Payments for proved oil and gas properties
|
(364,338 | ) | - | (364,338 | ) | |||||||
|
Net Cash Used in Investing Activities
|
(364,338 | ) | - | (364,338 | ) | |||||||
|
Cash Flows From Financing Activities:
|
||||||||||||
|
Capital contributions
|
18,351 | 8,603 | 53,492 | |||||||||
|
Proceeds from sale of common stock
|
695,030 | - | 695,030 | |||||||||
|
Net Cash Provided by Financing Activities
|
713,381 | 8,603 | 748,522 | |||||||||
|
Net increase (decrease) in cash
|
50,924 | - | 50,924 | |||||||||
|
Cash at beginning of period
|
- | - | - | |||||||||
|
Cash at end of period
|
$ | 50,924 | $ | - | $ | 50,924 | ||||||
|
Supplemental Cash Flow Information
|
||||||||||||
|
Cash paid for interest
|
$ | - | $ | - | $ | - | ||||||
|
Cash paid for income taxes
|
$ | - | $ | - | $ | - | ||||||
|
Noncash investing activities:
|
||||||||||||
|
Common stock issued to acquire Remington
|
$ | - | $ | - | $ | 1,662,000 | ||||||
|
Asset retirement cost
|
$ | 2,509 | $ | - | $ | 26,292 | ||||||
|
Accrued liability to acquire leases
|
$ | - | $ | - | $ | 15,881 | ||||||
|
Payable for purchase of oil and gas properties
|
$ | 76,041 | $ | - | $ | 76,041 | ||||||
See notes to the consolidated financial statements.
16
NORTH TEXAS ENERGY, INC.
(AN EXPLORATION STAGE COMPANY)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Business and Organization
North Texas Energy, Inc. (“the Company”) was incorporated in the State of Nevada on January 12, 2011. The Company intends to focus on re-entering non-producing oil fields and re-starting production with existing wells. On February 25, 2011, the Company entered into a Purchase and Sale Agreement with Remington Oil & Gas, Inc. (“Remington”) to acquire Remington’s interest in an oil and gas lease in Upshur County, Texas along with wellhead equipment and certain lease obligations.
The Company is in the exploration stage in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic No. 915 – Development Stage Entities. Since its inception, the Company has been engaged in acquiring interests in leases in the State of Texas, developing wells and searching for short-term and long-term sources of liquidity for its producing operations.
Note 2 - Summary of Significant Accounting Policies
Basis of Presentation
These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) and include the accounts of the Company and those of its wholly owned subsidiary. All significant intercompany accounts and transactions have been eliminated.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with an original maturity of three months or less.
Inventory
From time to time, crude oil production volumes may be stored as inventory and sold at a later time. Inventory is carried at the lower of production cost or market value. The first-in, first-out method is used for the crude oil inventory. As of December 31, 2013, inventory consisted of crude oil.
17
Oil and Gas Properties
The Company uses the full cost method of accounting for exploration and development activities as defined by the U.S. Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs for unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping the wells and any internal costs that are directly related to acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or other disposition of oil and gas properties are generally treated as a reduction in the capitalized costs of oil and gas properties, unless the impact of such a reduction would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.
The Company categorizes its full cost pools as costs subject to amortization and costs not being amortized. The sum of net capitalized costs subject to amortization, including estimated future development and abandonment costs, are amortized using the unit-of-production method.
Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed annually to determine if impairment has occurred. The amount of any impairment is transferred to the costs subject to amortization.
Ceiling Test and Impairment
Under the full cost method of accounting, a ceiling test is performed each quarter for proved properties. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment(“DD&A”) and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) with consideration of price change only to the extent provided by contractual arrangement, discounted at 10%, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated DD&A. The Company has proved properties subject to the full cost ceiling test as of December 31, 2013. As a result of the test performed on the Company’s proved properties, no impairment was considered necessary.
Asset Retirement Obligations
Asset retirement obligations (“ARO”) represent the future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. The ARO assets, which are carried on the balance sheet as part of the full cost pool, will be included in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability is included in the computation of the discounted present value of estimated future net revenues.
18
Income Taxes
Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
Realization of deferred tax assets is dependent upon sufficient future taxable income during the period that deductible temporary differences and carry-forwards are expected to be available to reduce taxable income. At December 31, 2013 and 2012, the Company has recorded a 100% valuation allowance as management believes it is likely that no deferred tax assets will be realized.
At December 31, 2013, the Company had net operating loss carry forwards of approximately $400,000 that will expire between 2029 through 2033.
Net Income (Loss) Per Share
Basic net income (loss) per share is computed by dividing the net income (loss) attributable to common shareholders by the weighted average number of common shares outstanding during the period. Diluted net income (loss) per share is computed by dividing the net income(loss) attributable to common shareholders by the weighted-average number of common and common equivalent shares outstanding during the period. Common share equivalents included in the diluted computation represent shares issuable upon assumed exercise of stock options and warrants using the treasury stock and “if converted” method. For periods in which net losses are incurred, weighted average shares outstanding is the same for basic and diluted loss per share calculations, as the inclusion of common share equivalents would have an anti-dilutive effect. As of December 31, 2013 and 2012, there were no potentially dilutive shares.
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end and the reported amounts of revenues and expenses during the year and the reported amount of proved natural gas and oil reserves. Management bases its estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments that are not readily apparent from other sources. Actual results could differ from these estimates and changes in these estimates are recorded when known.
Subsequent Events
The Company has evaluated all transactions through the date the consolidated financial statements were issued for subsequent event disclosure consideration.
Recently Issued Accounting Pronouncements
The Company does not expect the adoption of any recently issued accounting pronouncements to have a significant impact on its financial position, results of operations or cash flows.
19
Note 3 - Going Concern
As shown in the accompanying financial statements, the Company has incurred losses from operations and has not generated any revenue and has not secured continuous funding for the operation of its oil and gas producing activities. These factors raise substantial doubt about the Company’s ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern. In addition to the offering of securities for sale to the public, the Company currently is diligently searching for other short-term and long-term sources of liquidity for its producing operations.
Note 4 – Business Combination
Purchase of Remington
On February 25, 2011, the Company entered into a Purchase and Sale Agreement with Remington Oil & Gas, Inc. (“Remington”) effective January 11, 2011. Both Remington and the Company had no activities during the period from January 12, 2011 to February 25, 2011. Pursuant to the Purchase and Sale Agreement, the Company issued 831,000 common shares in exchange for 831,000 common shares of Remington. The Company assumed the $50,000 accrued lease obligation and acquired Remington’s oil and gas lease in Upshur County, Texas along with wellhead equipment. Remington’s shareholders prior to the transaction remained responsible for all the liabilities with the exception of the $50,000 accrued lease obligation assumed by the Company.
The Company acquired net assets with an aggregate fair value of $1,875,240 in exchange for 831,000 common shares of the Company valued at $1,662,000, resulting in the recognition of a bargain purchase gain of $213,240. The acquisition price of Remington was allocated to the assets acquired and liabilities assumed based upon their estimated fair values.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.
| Oil and gas properties | ||||
| Assets acquired: | $ | 1,950,263 | ||
| $ | 1,950,263 | |||
|
Liabilities assumed:
|
||||
|
Accrued lease obligation
|
50,000 | |||
|
Asset retirement obligation
|
25,023 | |||
|
Total liabilities assumed
|
75,023 | |||
|
Net assets acquired
|
1,875,240 | |||
|
Consideration transferred- Common stock issued valued at $2 per share
|
(1,662,000 | ) | ||
|
Bargain purchase gain
|
$ | 213,240 | ||
20
Note 5 – Oil and Gas Properties, Full Cost Method
The Company’s oil and gas properties at December 31, 2013 and 2012 are located in the State of Texas in the United States.
On December 18, 2013, the Company's oil and gas leases on its Upshur County Texas properties expired. The Company recorded an impairment expense of $1,238,887 related to the expired leases.
During 2013, the Company transferred $1,147,903 of oil and gas properties to costs subject to amortization from unproved properties.
For the year ended December 31, 2013, the Company invested $440,379 in the development of its oil and gas infrastructure and wells.
In the month of December 2013, the Company produced approximately 120 barrels of oil from the refurbished wells on the Balch Lease which is included in inventory at December 31, 2013.
Note 6 – Accrued Lease Liabilities
The Company has an accrued lease liability to KADs Oil, Inc., the lessor of the Company’s leases in both Upshur and Milam County, Texas. As a result of the Purchase and Sale Agreement with Remington, the Company assumed the leasehold obligation of $50,000. Payments are to be made when oil and gas is recovered and delivered to market at the rate of 25% of the sale price after all operating expenses until the $50,000 is fully repaid.
On May 10, 2011, the Company entered into an oil, gas and mineral lease agreement for its oil and gas properties located in Milam County, Texas. Pursuant to the lease agreement, the Company will pay the lessor $15,881 for the lease which is recorded as an accrued leasehold liability on the Company’s balance sheets at December 31, 2013 and 2012.
21
Note 7 – Asset Retirement Obligation
The following table provides a reconciliation of the changes in the estimated present value of asset retirement obligations for the years ended December 31, 2013 and 2012.
|
December 31,
2013
|
December 31,
2012
|
|||||||
|
Beginning asset retirement obligation
|
$ | 54,709 | $ | 49,293 | ||||
| Change of estimate | (2,509 | ) | ||||||
| Disposal of leases | (38,737 | ) | ||||||
|
Accretion expense
|
12,381 | 5,416 | ||||||
|
Ending asset retirement obligation
|
$ | 25,844 | $ | 54,709 | ||||
Note 8 – Equity
During 2013, the Company issued 348,265 common shares for $695,030 cash.
During 2011, the Company issued 5,000,000 shares to its founder. The shares were valued at $50 and recorded as share-based compensation. On February 25, 2011, the Company issued 831,000 shares, valued at $1,662,000, to acquire Remington.
Note 9 – Related Party Transaction
During the years ended December 31, 2013 and 2012, the Company’s Chief Executive Officer, Mr. Kevin Jones, contributed $18,351 and $8,603, respectively, to the Company.
Note 10 – Subsequent Events
Subsequent to December 31, 2013, the Company issued 60,250 common shares for $120,500 proceeds. The Company also received $78,500 of proceeds for the sale of 39,250 shares which have not been issued.
In January 2014, the Company obtained 205 acres of lease properties in Milam County, Texas for $14,834. The leases are for 3 years and are held by production.
Note 11 – Supplemental Information on Oil and Gas Exploration, Development and Production Activities (Unaudited)
This footnote provides unaudited information required by FASB ASC Topic 932, Extractive Activities—Oil and Gas.
22
Geographical Data
The following table shows the Company’s oil and gas revenues and lease operating expenses by geographic area:
|
2013
|
2012
|
|||||||
|
Revenues
|
||||||||
|
Milam County, Texas
|
$
|
-
|
$
|
-
|
||||
|
Production Costs
|
||||||||
|
Milam County, Texas
|
$
|
-
|
$
|
-
|
||||
Capital Costs
Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2013 and 2012 are summarized below:
|
2013
|
2012
|
|||||||
|
Proved properties being amortized
|
$ | 1,147,903 | $ | - | ||||
|
Accumulated depreciation, depletion, amortization and impairment
|
(313 | ) | - | |||||
|
Net capitalized costs
|
$ | 1,147,590 | $ | - | ||||
23
Amortization Rate
The amortization rate per unit was $2.61 per barrel for the year ended December 31, 2013. There was no amortization in 2012.
Acquisition, Exploration and Development Costs Incurred
Costs incurred in oil and gas property acquisition, exploration and development activities for the years ended December 31, 2013 and 2012 are summarized below:
|
2013
|
2012
|
|||||||
|
Development costs
|
$
|
440,379
|
$
|
-
|
||||
Reserve Information and Related Standardized Measure of Discounted Future Net Cash Flows
The unaudited supplemental information on oil and gas exploration and production activities has been presented in accordance with the SEC Modernization of Oil and Gas Reporting rules. The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company’s reserves. Volumes reported for proved reserves are based on reasonable estimates. These estimates are consistent with current knowledge of the characteristics and production history of the reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available.
Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.
The reserve estimates set forth below were prepared by a third party registered professional engineer, utilizing reserve definitions and pricing requirements prescribed by the SEC. The engineer had no interest in the Company and was objective in determining the results of the Company’s reserves.
24
Total estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated.
|
Gas (mcf)
|
Oil (bbls)
|
||||
|
Total proved reserves
|
|||||
|
Balance December 31, 2012
|
-
|
-
|
|||
|
Improved recovery
|
-
|
552,207
|
|||
|
Purchase of minerals in place
|
243,912
|
||||
|
Production
|
-
|
(120)
|
|||
|
Balance December 31, 2013
|
-
|
795,999
|
|||
|
Proved developed reserves
|
|||||
|
at December 31, 2012
|
-
|
-
|
|||
|
at December 31, 2013
|
-
|
365,319
|
|||
|
Proved undeveloped reserves
|
|||||
|
at December 31, 2012
|
-
|
-
|
|||
|
at December 31, 2013
|
-
|
430,680
|
|||
25
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is computed using average first-day-of the-month prices for oil and gas during the preceding 12 month period (with consideration of price changes only to the extent provided by contractual arrangements), applied to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated related future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated), and assuming continuation of existing economic conditions. For purposes of determining prices, we used the unweighted arithmetical average of the prices on the first day of each month within the 12-month period ended December 31, 2013. The average prices utilized for purposes of estimating our proved reserves were $97.61 per barrel of oil for our properties. Future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of continuing operations including property acquisitions and exploration. The estimated future cash flows are then discounted using a rate of ten percent a year to reflect the estimated timing of the future cash flows.
Standardized measure of discounted future net cash flows at December 31, 2013 and 2012 were as follows:
|
2013
|
2012
|
|||||||
|
Future cash flows from sales of oil and gas
|
$ | 77,697,462 | $ | - | ||||
|
Future production cost
|
(17,141,769 | ) | - | |||||
|
Future development cost
|
(2,518,331 | ) | - | |||||
|
Future income tax
|
(19,422,188 | ) | - | |||||
|
Future net cash flows
|
38,615,174 | - | ||||||
|
10% annual discount for timing of cash flow
|
(15,560,165 | ) | - | |||||
|
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves
|
$ | 23,055,009 | $ | - | ||||
The principal sources of changes in the standardized measure of the future net cash flows for each of the two years in the period ended December 31, 2013 and 2012 are:
| 2013 | 2012 | |||||||
|
Beginning of year
|
$ | - | $ | - | ||||
|
Purchase of minerals in place
|
10,937,046 | - | ||||||
|
Net change in income tax
|
(11,577,755 | ) | ||||||
|
Change due to revisions in standardized variables:
|
||||||||
|
Improved recovery
|
23,695,718 | - | ||||||
|
End of year
|
$ | 23,055,009 | $ | - |
26
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our principal executive and principal financial officers, we conducted an evaluation as of December 31, 2013 of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were not effective as of December 31, 2013.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of management, including our principal executive and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework, management concluded that our internal control over financial reporting was not effective as of December 31, 2013. Such conclusion reflects the lack of accounting experience of our now principal financial officer and a lack of segregation of duties. Until we are able to remedy these material weaknesses, we are relying on third party consultants to assist with financial reporting.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit smaller reporting companies to provide only management’s report in this annual report.
Changes in Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting during the fourth quarter of 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
27
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Executive Officers
Our executive officers as of December 31, 2013, and their ages and positions as of that date, are as follows:
|
Name
|
Age
|
Position
|
||
|
Kevin Jones
|
52
|
Chairman, Chief Executive Officer and Director
|
||
|
Sanah Marah
|
36
|
Chief Financial Officer
|
Mr. Kevin Jones
Mr. Jones is the founder of North Texas Energy, Inc. and holds BS, MS degrees, and PhD (ABD) in Physics. For nearly two years, early 1997 through late 1999, Mr. Jones served as a risk project manager for SRS Technologies. In late 1999, Mr. Jones joined General Dynamics where he served as a project and later a program manager for various defense related programs until late 2009. In late 2009, Mr. Jones joined ManTech International where he served as a program manager until he began serving full time as the CEO of North Texas Energy, Inc. in March 2012. Mr. Jones began serving as the director of North Texas Energy, Inc. in January 2011. None of Mr. Jones’ previous employers have any connection with North Texas Energy, Inc. He served as the initial Secretary for the Board of Directors of Remington Oil & Gas, Inc. for two months, January and February of 2010.
For the past 15 years, Mr. Jones has worked in program management and project management capacities. He managed $3 million to $50 million programs from inception to completion. Mr. Jones has managed programs and projects for the Missile Defense Agency, the Department of Defense (Army, Navy, and Marines), and the Department of Homeland Security. As a program manager, he was responsible for the executive management of a program (and it associated projects) and ensured the program ran effectively and efficiently. He managed the development and implementation of the programmatic scope, management plans, management schedules, life cycle and logistics cost analyses, cost trade-off analysis, and programmatic risk management assessments.
Mr. Jones has simultaneously managed disparate programs whereby different management techniques were brought to bear in totally different ways to obtain the desired results. He has built and led successful professional operations and he has turned dysfunctional operations into efficient cost productive programs.
28
Sanah Marah
Mr. Sanah Marah Jr. has been a Finance and Accounting Professional for the last 13 years. He attended the prestigious University of London and holds a Business and Finance degree and also attended LeTourneau University and graduated with a B.A. Accounting. He is a practicing Chartered Management Accountant, or C.M.A.
For the past 5 years, he served in two professional roles in which he managed budgets and projects ranging from $100 million to $800 million. In 2009, Mr. Marah joined the Accounting Team at Greyhound Lines Inc.’s (First Group America FGA Parent Company) corporate office in Dallas, Texas where his main focus was Inventory Management for all the U.S. and Canadian Operations and currently holds the position of Senior Accountant. He effectively managed all aspects of U.S. and Canadian Operations area including, Fuel, Oil, Tires, Engine and Cores. Components of these included Bus Refurbishment Project costing close to $200 million including budget and cash flow projections and spending. Before joining Greyhound Lines Inc., Mr. Marah pursued his private practice and he consulted with several companies including, Ascent Capital Group and J.F. Entertainment. As a Finance Consultant, he performed all finance and accounting roles from payables, receivables, cash management, budgeting & forecasting, inventory management, merger and acquisitions, fixed assets management and payroll.
Prior to private practice, Mr. Marah worked at Dean Foods Company, the largest Dairy Producer and Manufacturer in the U.S. In his tenure between 2003 and 2007, he focused on the inter-company reconciliations and eliminations for 45 entities. As a Senior Accountant, he introduced a cashless inter-company confirmation process between sister companies. During the same period, he performed Sarbanes-Oxley (SOX) implementation and testing to ensure proper internal controls. His last project before leaving was to ensure proper data integration and chart of accounts conversion to a new platform while constantly managing the Internal Financial Reporting for four divisions and the reconciliation of the financials between the General Ledger and Hyperion.
Earlier in his career, Mr. Marah was an International Accounting Analyst for Blockbuster's Corporate Office in Dallas Texas. In that capacity, he was responsible for the consolidations and eliminations of all the international operations in Europe, Latin America and Asia. He ensured minimal currency exposure and liabilities with the use of his hedging techniques. In addition, he created commentary on profit and loss fluctuations for each global region and reconciled statements from foreign GAAP to U.S. GAAP.
Mr. Marah began providing professional services to the Company on a part-time basis in January 2011.
No Officer or Director has been or is subject to any legal proceeding as identified in Regulation S-K Item 401(f)
29
Item 11. Executive Compensation.
The following table sets forth information concerning the total compensation paid or accrued by us during the fiscal years ended December 31, 2013 and 2012 to all individuals that served as our principal executive and principal financial officers or acted in a similar capacity for us at any time during the fiscal years ended December 31, 2012 and 2011.
SUMMARY COMPENSATION TABLE
|
Name and Principal Position
|
Year
|
Salary($)
|
Bonus($)
|
Stock Award($)
|
Option Award($)
|
Non-Equity
Incentive Plan($)
|
All Other
Compensation ($)
|
|
Kevin Jones, CEO
|
2012
2013
|
-
39,100
|
-
-
|
-
-
|
-
-
|
-
-
|
-
-
|
|
Sanah Marah, CFO
|
2012
2013
|
-
1,000
|
-
-
|
-
-
|
-
-
|
-
-
|
-
-
|
SUMMARY COMPENSATION TABLE
|
Name and Principal Position
|
Year
|
Salary($)
|
Bonus($)
|
Stock Award($)
|
Option Award($)
|
Non-Equity
Incentive Plan($)
|
All Other
Compensation ($)
|
|
Kevin Jones
|
2012
2013
|
-
-
|
-
-
|
-
-
|
-
-
|
-
-
|
-
-
|
30
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The following table sets forth information with respect to the beneficial ownership of our common stock known by us as of April 24, 2014 by:
|
• each person or entity known by us to be the beneficial owner of more than 5% of our common stock;
|
|
• each of our directors and executive officers; and
|
|
• all of our directors and executive officers as a group.
|
|
Class of Stock
|
Name & Address of Owner
|
Number of Shares
|
Portion of Class (%)
|
||||||
|
Common
|
Kevin Jones, CEO and Director
5057 Keller Springs Road, Suite 300
Addison, Texas 75001
|
5,000,000 | 80.13 | % | |||||
Item 13. Certain Relationships and Related Transactions, and Director Independence.
During the years ended December 31, 2013 and 2012, the Company’s Chief Executive Officer, Mr. Kevin Jones, contributed $18,351 and $8,603, respectively, to the Company.
31
Item 14. Principal Accounting Fees and Services.
The following table sets forth the fees billed by our principal independent accountants for each of our last two fiscal years for the categories of services indicated.
|
2013
|
2012
|
|||||||
|
Audit Fees
|
$ | 21,100 | $ | 8,200 | ||||
|
Audit Related Fees
|
- | - | ||||||
|
Tax Fees
|
- | - | ||||||
|
All Other Fees
|
- | - | ||||||
Audit fees: Consists of fees billed for the audit of our annual financial statements and review of our interim financial information and services that are normally provided by the accountant in connection with year-end and quarter-end statutory and regulatory filings or engagements.
Audit-related fees: Consists of fees billed for services relating to review of other regulatory filings including registration statements, periodic reports and audit related consulting.
Tax fees: Consists of professional services rendered by our principal accountant for tax compliance, tax advice and tax planning.
Other fees: Other services provided by our accountants.
32
EXHIBIT INDEX
|
EXHIBIT NUMBER
|
DESCRIPTION OF EXHIBIT
|
|
2.2
|
Purchase and Sales Agreement (Previously filed 2/23/2012)
|
|
3.1
|
Articles of Incorporation of North Texas Energy, Inc. (Previously filed 12/30/2011)
|
|
3.2
|
By-Laws of North Texas Energy, Inc. (Previously filed 12/30/2011)
|
|
31.1
|
Certification of Principal Executive Officer, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31.2
|
Certification of Principal Financial and Accounting Officer, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32.1
|
Certification of Principal Executive Officer, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32.2
|
Certification of Principal Financial and Accounting Officer, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
99.2
|
M W Balch Lease and New Diana Field 3-year EUR (Previously filed 5/16/2012)
|
|
101 INS
|
XBRL Instance Document*
|
|
101 SCH
|
XBRL Schema Document*
|
|
101 CAL
|
XBRL Calculation Linkbase Document*
|
|
101 DEF
|
XBRL Definition Linkbase Document*
|
|
101 LAB
|
XBRL Labels Linkbase Document*
|
|
101 PRE
|
XBRL Presentation Linkbase Document*
|
* The XBRL related information in Exhibit 101 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability of that section and shall not be incorporated by reference into any filing or other document pursuant to the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such filing or document.
33
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Dallas, State of Texas, on May 2, 2014.
|
Dated: May 2, 2014
|
North Texas Energy, Inc.
|
|
By: /s/ Kevin Jones
|
|
|
Kevin Jones
|
|
|
Chief Executive Officer and Director
|
NORTH TEXAS ENERGY, INC.
Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities indicated on May 2, 2014.
|
Signature
|
Title
|
Date
|
|
/s/ Kevin Jones
|
Chief Executive Officer and Director
|
May 2, 2014
|
|
Kevin Jones
|
(Principal Executive Officer)
|
|
|
/s/ Sanah Marah
|
Chief Financial Officer
|
May 2, 2014
|
|
Sanah Marah
|
(Principal Financial and Accounting Officer)
|
34