U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
From the transition period from ____________ to ___________.
Indicate by check mark whether the registrant is a large accelerated filer, and 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.
As of May 10, 2014, there were outstanding 499,083,626 shares of common stock, $0.001 par value per share.
See accompanying notes to the consolidated and combined financial statements.
See accompanying notes to the consolidated and combined financial statements.
See accompanying notes to the consolidated and combined financial statements.
1. Organization and nature of operations
In the opinion of management, the accompanying unaudited consolidated financial statements include all necessary adjustments (consisting of normal recurring adjustments) and present fairly the consolidated financial position of Breitling Energy Corporation and Subsidiaries (the "Company" or “Breitling”) as of March 31, 2014 and the results of their operations for the three months ended March 31, 2014 and 2013 and the results of their cash flows for the three months ended March 31, 2014 and 2013, in conformity with generally accepted accounting principles for interim financial information applied on a consistent basis. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results to be expected for the full year.
2. Organization and nature of operations
Breitling Energy Corporation was incorporated in the State of Nevada on December 13, 2000 under the name “Folix Technologies, Inc.” On August 18, 2004, the Company changed its name to Dragon Gold Resources, Inc. On June 22, 2007, the Company changed its name to Edgeline Holdings, Inc. and on March 11, 2008 to Oncolin Therapeutics, Inc. On September 7, 2010, the Company changed its name to Bering Exploration, Inc. and on January 20, 2014, to Breitling Energy Corporation.
3. Liquidity
For the three months ended March 31, 2014, the Company has generated net income of $6,712,217, and cash flow from operations of $2,037,841. The Company has incurred losses and negative cash flows from operations in recent years and expects to continue to incur operating losses until revenues from all sources reach a level sufficient to support its on-going operations. The Company’s liquidity will largely be determined by its ability to raise capital from debt, equity, or other forms of financing, by the success of its product offerings, by developing additional product offerings, and by reducing expenses associated with operations. The Company’s management believes that its cash resources at March 31, 2014, will be sufficient to meet current obligations and fund its operating activities through December 31, 2014.
In the absence of a sufficient increase in revenues, the Company will need to do one or more of the following in the next 12 months to meet its planned level of expenditures: (a) raise additional capital; (b) reduce spending on operations; or (c) restructure its operations. A capital raise could take any number of forms including but not limited to: additional debt, additional equity, asset sales, or other forms of financing as dictated by its needs and its view toward its overall capital structure. However, additional financing might not be available on acceptable terms, if at all, and such financing might only be available on terms dilutive or otherwise detrimental to its stockholders or its business. As such, the Company’s Chief Executive Officer, Mr. Chris Faulkner, has personally guaranteed his ability and financial wherewithal to ensure the Company can continue until at least January 1, 2015. This personal guaranty may include reduction of salary, capital or debt contributions and/or other measures, as needed.
4. Summary of significant accounting policies
Principles of Consolidation and Combination
The consolidated and combined financial statements reflect the historical combined results of the Predecessors prior to the reverse recapitalization completed on December 9, 2013, and the consolidated results of the Company thereafter. All intercompany and inter-entity transactions have been eliminated in the consolidation and combination.
Fair Value Measurements
The Company has adopted and follows ASC 820, Fair Value Measurements and Disclosures, for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC 820 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by ASC 820 are:
Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 — Inputs (other than quoted market prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Valuation of instruments includes unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities.
As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date. The carrying amounts of the Company’s financial assets and liabilities, such as cash and cash equivalents, oil and natural gas sales receivable, and accounts payable and accrued liabilities, approximate their fair values because of the short maturity of these instruments.
Cash
The Company considers all highly-liquid debt instruments with original maturities of three months or less to be cash equivalents. As of March 31, 2014 and 2013, the Company did not hold any cash equivalents. The Company maintains its cash balances in financial institutions which are insured by the Federal Deposit Insurance Corporation (“FDIC”). The interest bearing cash accounts maintain FDIC coverage of up to $250,000 per institution.
Other Property and Equipment
Other property and equipment, which includes furniture, vehicles, software, and office equipment, is stated at cost less accumulated depreciation and amortization. Depreciation and amortization is computed using the straight-line method over the estimated useful lives of the assets. Furniture and office equipment are generally depreciated over a useful life of ten years, vehicles over a useful life of five years, and software over a useful life of three years.
Impairment of Long-Lived Assets
The Company assesses the impairment of long-lived assets when circumstances indicate that the carrying value may not be recoverable. The Company determines if impairment has occurred through adverse changes. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. For the three months ended March 31, 2014, and any prior applicable periods, no circumstances indicated an unrecoverable carrying value of the long-lived assets.
Asset Retirement Obligations
The Company follows the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires the Company to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted as part of the oil and natural gas property. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company’s asset retirement obligations relate to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties.
Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under ASC 820. Additionally, because of the subjectivity of assumptions and the relatively long lives of the Company’s wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.
Revenue Recognition
The Company has entered into drilling contracts with outside working interest owners to develop leasehold acreage that the Company has acquired. In these arrangements, the Company acquired a working interest in a prospect pursuant to an oil and gas lease, and then sold a portion of a well’s working interest on the acquired lease to outside working interest owners with a third party drilling agreement. Title to the lease property was not conveyed to the outside working interest owners. The outside working interest owner purchases a working interest directly in the well bore. The working interest purchased in these drilling agreements is an ownership interest in which the working interest holder is obligated to bear the cost of drilling, testing, completing, equipping and operating the well. The Company typically sells a large portion of the working interests and has a third-party operate the projects.
In a third party drilling agreement, the Company agrees to sell a percentage of the well’s working interest to outside working interest owners and to pay for all costs of identifying, acquiring mineral rights to, drilling, testing, completing and equipping the well for initial production at a fixed price. If the actual costs of these activities exceed the price the Company charged to the outside working interest owners, the Company is obligated to pay the excess cost. If the actual costs are less, the Company retains the excess over actual costs. The Company bears 100% of the risk should actual cost exceed estimated costs of a project for both the Company’s working interest and the working interest sold. When the well is completed as a commercially productive well, the Company and the outside working interest owners bear the cost of operating the well according to each party’s proportionate working interest percentage.
When the Company entered into a third party drilling agreement, outside working interest owners entered into a signed contract with the Company pursuant to which they agree to share in the prospect acquisition costs and drilling costs. The prospect acquisition costs include geophysical and geographical costs, costs to lease the mineral rights, and other costs as required so the drilling of the project can proceed. Drilling costs are those costs incurred to build the drilling location, drill and log the well, and if the well is successful, to complete and test the well. Once drilling begins, the well is generally completed within 30 to 60 days. The Company bases the price at which it sells working interests under the third party drilling agreement on its estimates of the costs described above. Since the outside working interest owner’s interest in the prospect is limited to the well, and not the lease, the outside working interest owner does not have a legal right to participate in additional wells drilled within the same lease. However, it is the Company’s policy to offer to outside working interest owners in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well with similar third party drilling agreement terms.
The Company recognizes revenues associated with its third party contracts when development steps outlined in the contract have been achieved on a well under development. Revenues are earned in accordance with the third party contracts when the following development steps are met on the respective oil and natural gas well under development: completion of the drilling/testing of the well and completion of the completion/equipping phase of the well. Any cash collected under the third party contracts that have not met one of the development steps is deferred and presented as deferred revenue from third party contracts on the combined balance sheets. The third party revenue is recorded on a gross basis with the associated drilling costs, as agreed to in the third party contract, being deferred until the associated revenue is recognized. Early recognition of loss is recorded if it is determined that the well cost will exceed the applicable revenue received on the specific well. Total third party drilling revenues recognized for the three months ended March 31, 2014 and 2013 were approximately $10,175,000 and $3,183,000, respectively. As of March 31, 2014, the Company recognized $4,609,000 that was previously deferred as of December 31, 2013.
The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells. The Company will also enter into physical contract sale agreements through its normal operations. Revenue from the sale of natural gas and crude oil is recognized when title to the commodities passes.
Gas imbalances are accounted for using the sales method. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. However, the Company has no history of significant gas imbalances.
Sales-Based Taxes
The Company incurs severance tax on the sale of its production which is generated in Texas, North Dakota and Oklahoma. These taxes are reported on a gross basis and are included in lease operating expense within the accompanying combined statements of operations. Sales-based taxes for the three months ended March 31, 2014 and 2013 were approximately $9,000 and $8,000, respectively.
Lease Operating Expenses
Lease operating expenses include severance and production taxes, field personnel salaries, saltwater disposal, ad valorem taxes, repairs and maintenance, and other operating expenses. Lease operating expenses are expensed as incurred. The Company recognized $45,000 and $151,000 for the three months ended March 31, 2014 and 2013, respectively for lease operating expenses.
General and Administrative Expense
General and administrative expenses are reported net of recoveries from owners in properties operated by the Company and net of amounts related to lease operating activities capitalized pursuant to the full-cost method of accounting.
Net Income (Loss) per Common Share
Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to stockholders by the weighted average number of common shares outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from stock options, non-vested share appreciation rights and non-vested restricted shares.
Use of Estimates
The preparation of combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
The Company’s estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and natural gas prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.
5. Fair Value Measurements
As of March 31, 2014 and December 31, 2013, the Company had no assets which were measured at fair value.
The following table presents information about the Company’s liabilities measured at fair value as of March 31, 2014 and December 31, 2013:
| | | Level 1 (unaudited) | | | Level 2 (unaudited) | | | Level 3 (unaudited) | | | Balance as of March 31, 2014 | |
| Liabilities (at fair value): | | | | | | | | | | | | |
Asset retirement obligations | | $ | | | | $ | | | | $ | 38,102 | | | $ | 38,102 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Balance as of | |
| | | Level 1 | | | Level 2 | | | Level 3 | | | December 31, 2013 | |
| | | | | | | | | | | | | | | | | |
| Liabilities (at fair value): | | | | | | | | | | | | | | | | |
Asset retirement obligations | | $ | | | | $ | | | | $ | 37,337 | | | $ | 37,337 | |
6. Other property and equipment
The following table presents a summary of the Company’s other property and equipment:
| | | March 31, | | | December 31, | |
| | | 2014 | | | 2013 | |
| | | | | | | |
Furniture | | $ | 194,275 | | | $ | 194,275 | |
Vehicles | | | 25,708 | | | | 25,708 | |
Software | | | 21,047 | | | | 21,047 | |
Office equipment | | | 86,919 | | | | 71,627 | |
Less: Accumulated depreciation | | | (162,740 | ) | | | (159,036 | ) |
| | | | | | | | | |
Total other equipment, net of accumulated deprecation | | $ | 165,209 | | | $ | 153,621 | |
7. Commitment and Contingencies
Legal
From time to time, the Company may become subject to proceedings, lawsuits and other claims in the ordinary course of business including working interest rescissions and operator disputes. Such matters are subject to many uncertainties, and outcomes are not predictable with assurance. As of March 31, 2014 and December 31, 2013, the Company accrued $166,000 to settle working interest rescissions.
Oil and Natural Gas Regulations
The Company is subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes that it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, environmental matters are subject to regulation by various federal and state agencies.
RESULTS OF OPERATIONS
For the three months ended March 31, 2014 compared to three months ended March 31, 2013:
Revenue. During the three months ended March 31, 2014, the Company generated revenues of $16,911,124, an increase of $8,951,413, or 112% as compared to the same period last year. The Company recognized deferred revenues of $4,609,041 and Company has increased revenues through sales of royalty interests and third party drilling in oil and gas properties.
Total Expenses. During the three months ended March, 2014, total expenses, which include costs of third party drilling, marketing, professional fees, depreciation, operating costs and general and administrative expenses, were $10,074,344 compared to $7,642,097 during the same period in 2013. This change represents an increase of $2,432,247, or 32%. The increase is primarily due to increased general and administrative expenses and professional fees. These increases are due primarily to additional services necessary to support our 74% increase in revenue and the costs associated with becoming a public company.
LIQUIDITY AND CAPITAL RESOURCES
For the three months ended March 31, 2014:
We have improved our net working capital deficit as of March 31, 2014 by $6,674,070 to $614,733 from $7,288,803 as of December 31, 2013. The improvement was generated by the reversal of deferred revenue and cash flow generated from operations.
Net cash provided in operating activities of $2,037,841 for three months ended March 31, 2014 decreased from cash provided by operations of $2,666,710 for the same period last year, a decrease of $628,869. The decrease is primarily due to the increased costs associated with being a public company.
Net cash used in investing activities of $15,292 was primarily utilized to acquire office equipment as we add additional staff necessary for increased revenues.
Off-Balance Sheet Arrangements
From time to time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of March 31, 2014, the off-balance sheet arrangements and transactions that we had entered into included operating lease agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources currently or in the future.
Not applicable.
Our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), which we refer to as disclosure controls, are controls and procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act, such as this Quarterly Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. There are inherent limitations to the effectiveness of any control system. A control system, no matter how well conceived and operated, can provide only reasonable assurance that its objectives are met. No evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.
As of March 31, 2014 an internal evaluation was carried out under the supervision and with the participation of our management, including the CEO and the CFO, of the effectiveness of the design and operation of our disclosure controls. Based upon that evaluation, the CEO and the CFO concluded that, as of such date, the design and operation of these disclosure controls were effective to accomplish their objectives at the reasonable assurance level.
The Company is not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to the industry. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, management believes that the resolution of any proceeding will not have a material adverse effect on the financial condition or results of operations.
During the first quarter of 2014, there were no material changes to the Risk Factors disclosed in “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.
The Company had no unregistered sales of its securities from January 1, 2014 through May 5, 2014.
None.
Not applicable.
None.
| 31.1* | | Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | |
| 31.2* | | Certification of the Chief Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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| 32.1** | | Certification of the Chief Executive Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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| 32.2** | | Certification of the Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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| 101.INS* | | XBRL Instance Document. |
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| 101.SCH* | | XBRL Taxonomy Extension Schema Document. |
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| 101.CAL* | | XBRL Taxonomy Extension Calculation Linkbase Document. |
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| 101.DEF* | | XBRL Taxonomy Extension Definition Linkbase Document. |
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| 101.LAB* | | XBRL Taxonomy Extension Label Linkbase Document. |
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| 101.PRE* | | XBRL Taxonomy Extension Presentation Linkbase Document. |
| * | Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act or Section 18 of the Exchange Act, and otherwise are not subject to liability. |
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.
| | By: | /s/ Chris Faulkner | |
| | | Chris Faulkner, President, Chief Executive Officer, Chairman of the Board of Directors, and duly authorized Officer | |
| | | | |
| | By: | /s/ Rick Hoover | |
| | | Chief Financial Officer, principal accounting officer, and duly authorized Officer | |
| | | | |
| | | Date: May 15, 2014 | |
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