NOTES TO FINANCIAL STATEMENTS
For the Years Ended December 31, 2015 and 2014
|
1.
|
Organization and Nature of Operations
|
Arête Industries, Inc. (“Arête” or the “Company”), is a Colorado corporation that was incorporated on July 21, 1987. The Company is in the business of exploration for and production of oil and natural gas. The Company’s primary area of oil exploration and production is in Colorado, Montana, Kansas, and Wyoming.
The Company seeks to focus on acquiring interests in traditional exploratory and development oil and gas ventures, and seek properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas, which may include shut-in wells, in-field development, stripper wells, enhanced recovery, re-completion and re-working projects. In addition, the Company’s strategy includes the purchase and sale of acreage prospective for oil and natural gas and seeking to obtain cash flow from the sale and farm out of such prospects.
|
2.
|
Summary of Significant Accounting Policies
|
Use of Estimates
Preparation of the Company’s financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make various assumptions, judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.
The most significant areas requiring the use of assumptions, judgments and estimates relate to the volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future asset retirement obligations, impairments of undeveloped properties, and in valuing stock-based payment awards.
The only component of comprehensive income that is applicable to the Company is net income (loss). Accordingly, a separate statement of comprehensive income (loss) is not included in these financial statements.
Cash Equivalents
For purposes of the statement of cash flows, the Company considers cash and all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Accounts Receivable
The Company’s receivables consist mainly of trade account receivables from working interests in oil and gas production from partners with interests in common properties. Collectability is dependent upon the financial wherewithal of each entity and is influenced by the general economic conditions of the oil and gas industry. The Company records an allowance for doubtful accounts on a case by case basis once there is evidence that collection is not probable.
Gas Gathering System, Furniture and Equipment
The Company’s gas gathering system and its furniture and equipment are stated at cost. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of normal maintenance and repairs is charged to operating expenses as incurred. Upon disposal of an asset, the cost of the asset and the related accumulated depreciation are removed from the accounts, and any gains or losses will be reflected in current operations. For the gas gathering system, depreciation is computed using the straight line method over an estimated useful life of ten years. Depreciation of furniture and equipment is computed using the straight-line method over an estimated useful life of five years. At December 31, 2015, the Company wrote this asset off by recording an impairment charge against the gas gathering system of $56,648. Furniture and equipment was fully depreciated at December 31, 2015.
Oil and Gas Producing Activities
The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has proved reserves. If an exploratory well does not result in proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized.
Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production DD&A rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.
Unevaluated oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unevaluated oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage.
The Company reviews its proved oil and gas properties for impairment annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Once incurred, a write-down may not be reversed in a later period. At December 31, 2015, the Company recorded impairment against its oil and gas properties in the amount of $3,231,000 due to the sustained decline in oil prices in 2015 and forecasts for future prices. There was no impairment at December 31, 2014.
The provision for DD&A of oil and gas properties is calculated based on proved reserves on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel equivalents, BOE, at the rate of six Mcf of natural gas to one barrel of oil. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration.
Asset Retirement Obligations
The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the Consolidated Statements of Operations. See Note 8 – Asset Retirement Obligation.
Revenue Recognition
The Company records revenues from the sale of crude oil, natural gas and natural gas liquids (“NGL”) when delivery to the purchaser has occurred and title has transferred. The Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company will record revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over and under produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2015 and 2014 were not material.
Environmental Liabilities
Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2015 and 2014, the Company had not accrued for nor been fined or cited for any environmental violations that would have a material adverse effect upon capital expenditures, operating results or the competitive position of the Company.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.
Stock-Based Compensation
The Company did not grant any stock options or warrants during the years ended December 31, 2015 and 2014 and no options or warrants were outstanding at any time during these years. The Company has issued shares of common stock for services performed by officers, directors and unrelated parties during 2015 and 2014. The Company has recorded these transactions based on the value of the services or the value of the common stock, whichever is more readily determinable.
Income Taxes
Income taxes are reported in accordance with GAAP, which requires the establishment of deferred tax accounts for all temporary differences between the financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted.
Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.
Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency. A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated.
Fair Value of Financial Instruments
Cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities and notes payable are carried in the Consolidated Financial Statements in amounts which approximate fair value because of the short-term maturity of these instruments.
Concentration of Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash equivalents and revenue receivables. The Company periodically maintains cash balances at a commercial bank in excess of the Federal Deposit Insurance Corporation insurance limit of $250,000. At December 31, 2015, the Company’s uninsured cash balance was $271,666. The Company received 82% and 84% of its oil and gas production revenue from two purchasers during fiscal years ended December 31, 2015 and 2014, respectively.
The concentration of credit risk in the oil and gas industry affects the overall exposure to credit risk because customers may be similarly affected by changes in economic or other conditions. The creditworthiness of customers and other counterparties is subject to continuing review.
Earnings Per Share
Basic net income (loss) per share of common stock is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted net income (loss) attributable to common stockholders is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding and other dilutive securities. The only potentially dilutive securities for the diluted earnings per share calculations consist of Series A2 preferred stock that is convertible into common stock at an exchange price of $2.00 per common share. As of December 31, 2015, the convertible preferred stock had an aggregate liquidation preference of $2,670,000 and was convertible to 1,335,000 shares of common stock. These shares were excluded from the earnings per share calculation because they would be anti-dilutive. All of the Series A1 preferred stock was redeemed during the year ended December 31, 2014, therefore, there was no outstanding preferred stock at December 31, 2014.
The following table sets forth the calculation of basic and diluted earnings per share:
|
|
|
Year ended December 31,
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Net income (loss) available to common shareholder’s – Basic
|
|
$
|
(4,747,053
|
)
|
|
$
|
70,945
|
|
|
Plus: Preferred stock dividends
|
|
|
-
|
|
|
|
-
|
|
|
Net income (loss) available to common shareholder’s – Diluted
|
|
$
|
(4,747,053
|
)
|
|
$
|
70,945
|
|
|
Weighted average common shares outstanding – Basic
|
|
|
12,882,000
|
|
|
|
12,450,000
|
|
|
Add: Dilutive effect of stock options
|
|
|
-
|
|
|
|
-
|
|
|
Add: Dilutive effect of preferred stock
|
|
|
-
|
|
|
|
-
|
|
|
Weighted average common shares outstanding – Diluted
|
|
|
12,882,000
|
|
|
|
12,450,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.37
|
)
|
|
$
|
0.01
|
|
|
Diluted
|
|
$
|
(0.37
|
)
|
|
$
|
0.01
|
|
New Accounting Pronouncements
In June 2014, the FASB issued ASU No. 2014-12, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period (“ASU 2014-12”). The amendments in ASU 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. A reporting entity should apply existing guidance in Accounting Standards Codification Topic No. 718, “Compensation – Stock Compensation” (“ASC 718”), as it relates to awards with performance conditions that affect vesting to account for such awards. The amendments in ASU 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. Entities may apply the amendments in ASU 2014-12 either: (a) prospectively to all awards granted or modified after the effective date; or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The adoption of ASU 2014-12 is not expected to have a material effect on the Company’s consolidated financial statements or disclosures.
In April 2014, the FASB issued ASU 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU 2014-08 changes the criteria for reporting a discontinued operation. Under the new pronouncement, a disposal of a part of an organization that has a major effect on its operations and financial results is a discontinued operation. The Company is required to adopt ASU 2014-08 prospectively for all disposals or components of its business classified as held for sale during fiscal periods beginning after December 15, 2014. The adoption of ASU 2014-08 did not have a material effect on the Company’s consolidated financial statements or disclosures.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”), which provides guidance for revenue recognition. ASU 2014-09 affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets and supersedes the revenue recognition requirements in Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU also supersedes some cost guidance included in Subtopic 605-35, “Revenue Recognition- Construction-Type and Production-Type Contracts.” ASU 2014-09’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which a company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under today’s guidance, including identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. ASU 2014-09 is effective for the Company beginning January 1, 2017 and, at that time, the Company may adopt the new standard under the full retrospective approach or the modified retrospective approach. Early adoption is not permitted. The Company is currently evaluating the method and impact the adoption of ASU 2014-09 will have on the Company’s consolidated financial statements and disclosures.
In August 2014, the FASB issued ASU No. 2014-15,
Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern
(“ASU 2014-15”). ASU 2014-15 will explicitly require management to assess an entity’s ability to continue as a going concern, and to provide related footnote disclosure in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016. Earlier adoption is permitted. We are currently evaluating the impact of the adoption of ASU 2014-15.
In April 2015, the Financial Accounting Standards Board (“FASB”) issued new authoritative accounting guidance requiring debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the related debt liability. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company's financial statements and disclosures.
In November 2015, the FASB issued ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. This guidance eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments may be applied prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Company does not expect this to impact its operating results or cash flows.
In September 2015, the FASB issued Accounting Standards Update No. 2015-16 (ASU 2015-16): Business Combinations (Topic 805), effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, to simplify the accounting for measurement-period adjustments for an acquirer in a business combination. ASU 2015-16 requires an acquirer to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The acquirer is required to adjust its financial statements for the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts calculated as if the accounting had been completed at the acquisition date. We are currently evaluating the provisions of ASU 2015-16 and assessing the impact, if any, it may have on our financial position and results of operations.
|
3.
|
Acquisitions and Dispositions of Oil and Gas Properties
|
Acquisitions
In 2011, the Company entered into a purchase and sale agreement (“DNR and Tindall PSA”) and other related agreements and documents with Tucker Family Investments, LLLP, which we refer to as “Tucker”; DNR Oil & Gas, Inc. which we refer to as “DNR”; and Tindall Operating Company, which we refer to as “Tindall”, and collectively we refer to these parties as the “Sellers”, for the purchase of certain oil and gas operating properties in Colorado, Kansas, Wyoming, and Montana. DNR is owned primarily by an officer and director of the Company, Charles B. Davis, and he is an affiliate of Tucker and Tindall. The consideration for the purchase was determined by bargaining between management of the Company and Mr. Davis, and the Company used reports of independent engineering firms to analyze the purchase price. The base purchase price was paid in full on September 29, 2011.
On January 19, 2016, but effective December 31, 2015, (the "Effective Date") we entered into a Settlement Agreement with Tucker, DNR and Tindall regarding the DNR and Tindall PSA and other related matters. In consideration of the amounts indicated below, the parties (i) terminated Exhibits C and C-2 to the DNR and Tindall PSA for all purposes; (ii) extinguished all liabilities of the Company under Exhibit C of the DNR and Tindall PSA including $250,000 related to the increase in oil prices after the acquisition; (iii) agreed that the promissory note of $792,151 due to DNR (See Note 5 – Notes and Advances Payable) and accrued interest thereon was paid in full; and (iv) released each other against any and all claims which have been raised or could have been raised among them. Specifically, Exhibits C and C-2 to the DNR and Tindall PSA related to potential payments that would have needed to have been made by the us in the event oil prices increased to certain levels and related to certain payments to have been made by us in the event we sold certain properties purchased under the DNR and Tindall PSA. Exhibits C and C-2 were terminated and extinguished (including any amounts owed thereunder including $250,000 under Exhibit C to the DNR and Tindall PSA) in exchange for 25 fully paid nonassessable restricted shares of our 7% Series A2 Convertible Preferred Stock. Consideration to pay the above promissory note in full consisted of the issuance to DNR of 65 fully paid, nonassessable restricted shares of its 7% Series A2 Convertible Preferred Stock, and paying DNR $303,329 in cash. A description of the terms of the 7% Series A2 Convertible Preferred Stock, including its terms of conversion into shares of the Company's common stock is set forth in Note 4 below. The Company recorded an expense of $141,099 included in other operating expense in the statement of operations as a result of this transaction.
On December 30, 2015, the Company completed an asset acquisition pursuant to a purchase and sale agreement executed on November 25, 2015, but effective December 1, 2015 (the "Wellstar Purchase and Sale Agreement ") with Wellstar Corporation (the "Seller"), an unaffiliated corporation. The assets acquired were producing oil and gas leases in Sumner County, Kansas and Kimball County, Nebraska (collectively, the "Properties" and individually, the "Padgett Properties" and the "Nebraska Properties"). The Company acquired 51% of Seller's interest (ranging from 47% to 100% of the working interests) in the Padgett Properties and acquired 100% of the Seller's interest (100% of the working interests) in the Nebraska Properties for aggregate consideration of $1,100,000 and the issuance of 1,000,000 shares of the Company's restricted common stock valued at $0.10 per share at the date of closing, or $100,000.
The table below presents the purchase price allocation for the Wellstar Purchase and Sale Agreement:
|
Purchase Price allocation:
|
|
Amount
|
|
|
|
|
|
|
|
Cash
|
|
$
|
1,100,000
|
|
|
Common Stock
|
|
|
100,000
|
|
|
Total Consideration
|
|
$
|
1,200,000
|
|
|
|
|
|
|
|
|
Oil and gas properties
|
|
$
|
1,404,493
|
|
|
Asset retirement obligation assumed
|
|
|
(204,493
|
)
|
|
Total Purchase price allocation
|
|
$
|
1,200,000
|
|
Pro-Forma information acquisition (unaudited)
The table below reflects unaudited pro forma results as if the acquisition of oil and gas properties had taken place as of January 1, 2014:
|
|
|
December31,
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Total revenue
|
|
$
|
1,294,069
|
|
|
$
|
3,384,674
|
|
|
Net income (loss)
|
|
|
(4,773,679
|
)
|
|
|
455,736
|
|
|
Net income (loss) applicable to common shareholders
|
|
|
(4,773,679
|
)
|
|
|
464,312
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share
|
|
$
|
(0.34
|
)
|
|
$
|
0.03
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(0.34
|
)
|
|
$
|
0.03
|
|
The unaudited pro forma data gives effect to the actual operating results of the acquired properties prior to the acquisition, adjusted to include the pro forma effect of depreciation, depletion, amortization and accretion based on the purchase price of the properties.
|
4.
|
Oil and Gas Properties
|
The following table sets forth information concerning the Company’s oil and gas properties:
|
|
|
December31,
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Proved oil and gas properties at cost, net of impairment
|
|
$
|
8,683,273
|
|
|
$
|
10,222,668
|
|
|
Unevaluated oil and gas properties at cost, net of impairment
|
|
|
154,836
|
|
|
|
348,836
|
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(3,223,000
|
)
|
|
|
(2,476,898
|
)
|
|
Oil and gas properties, net
|
|
$
|
5,615,109
|
|
|
$
|
8,094,606
|
|
During the years ended December 31, 2015 and 2014, the Company recorded depletion expense of $746,104 and $701,042, respectively. The Company recorded impairment expense of $3,037,000 and $194,000 against proved and unevaluated oil and gas properties, respectively at December 31, 2015. There was no impairment expense during fiscal year ended December 31, 2014.
|
5.
|
Fair Value Measurements
|
FASB ASC 820, “Fair Value Measurements and Disclosures”, establishes a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under FASB ASC 820 are described as follows:
|
|
-
|
Level 1 – Observable inputs, such as unadjusted quoted prices in active markets, for substantially identical assets and liabilities.
|
|
|
-
|
Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices for similar assets and liabilities in active markets, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability.
|
|
|
-
|
Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by management. The assets or liabilities fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs.
|
The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Further, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions.
Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment. The following table sets forth by level, within the fair value hierarchy, the Company’s assets and liabilities at fair value on a recurring basis as of December 31, 2015:
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Net Book Value
|
|
|
Total Pre-tax
(Non-cash)
Impairment Loss
|
|
|
Proved oil and gas properties at cost, net of impairment
|
|
|
-
|
|
|
|
-
|
|
|
$
|
315,138
|
|
|
$
|
3,386,585
|
|
|
$
|
3,071,447
|
|
|
Unevaluated oil and gas properties at cost, net of impairment
|
|
|
-
|
|
|
|
-
|
|
|
$
|
154,783
|
|
|
$
|
314,336
|
|
|
$
|
159,553
|
|
|
Gas gathering system (1)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
56,648
|
|
|
$
|
56,648
|
|
(1) The gas gathering system was written off entirely at December 31, 2015.
The fair values of the properties were determined using discounted cash flow models. The discounted cash flows were based on management’s expectations for the future. The inputs included estimates of future crude oil and natural gas production, commodity prices based on sales contracted terms or commodity price curves as of the date of the estimate, estimated operating and development costs, as a risk-adjusted discount rate of 10%.
The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities and long term debt in our balance sheet approximates fair value as of December 31, 2015 and December 31, 2014.
Stockholders’ Equity
Common Stock
During the year ended December 31, 2014, the Company purchased an option to acquire rights in minerals owned by William W. Stewart (related party) for 150,000 shares of common stock valued at $34,500.
On January 30, 2014, the Company entered into a Direct Stock Purchase Agreement with Burlingame Equity Investors II L.P. and Burlingame Equity Investors Master Fund, L.P., whereby the Company purchased an aggregate 1,200,000 shares of its common stock from these entities at a price of $0.19 per share for total consideration of $228,000.
During the year ended December 31, 2015, the Company issued 736,954 shares of common stock as compensation for services; 480,288 shares of common stock were issued for board services ranging in value from $0.10 to $0.20 per share and 256,666 shares of common stock were issued for consulting services provided by three related parties ranging in value from $0.10 to $0.16 per share.
The Company issued 1,000,000 shares of common stock valued at $0.10 per share or $100,000 related to the Wellstar Purchase and Sale Agreement that was executed on December 30, 2015. See Note 3 – Acquisitions, for additional information regarding this transaction.
Preferred Stock
On September 29, 2011, the Company completed a private placement of its Series A1 Preferred Stock which resulted in the issuance of 522.5 shares for gross proceeds of $5,225,000.
Effective June 28, 2013, several holders of the Company’s Series A1 Convertible Preferred Stock elected to convert shares of such stock into the Company’s common stock at a redemption price of $0.75 per common share. In connection with those redemptions all such holders agreed to waive all dividend rights on their shares of Series A1 Preferred Stock subsequent to March 30, 2013. Information regarding the conversions is set forth below.
|
|
|
|
|
|
|
|
|
|
|
Number of Shares of Series
A1 Preferred Stock Converted
|
|
Number of
Common Shares Issued
|
|
|
Burlingame Equity Investors II, LP
|
|
16
|
|
|
100,800
|
|
|
Burlingame Equity Investors Master Fund, LP
|
|
184
|
|
|
1,159,200
|
|
|
Charles B. Davis*
|
|
100
|
|
|
1,333,333
|
|
|
Tucker Family Investments LLLP
|
|
25
|
|
|
333,333
|
|
|
Mark Venjohn
|
|
10
|
|
|
133,333
|
|
|
Pete Haman
|
|
35
|
|
|
466,667
|
|
|
Nicholas L. Scheidt*
|
|
100
|
|
|
1,333,333
|
|
|
Michael J. Finney
|
|
5
|
|
|
66,667
|
|
|
William and Sara Kroske
|
|
2.5
|
|
|
33,333
|
|
|
Michael A. Geller
|
|
10
|
|
|
133,333
|
|
|
John H. Rosasco
|
|
10
|
|
|
133,333
|
|
|
Lyon Oil & Gas Company
|
|
10
|
|
|
133,333
|
|
|
T P Furlong
|
|
5
|
|
|
66,667
|
|
|
*
|
Executive Officer and Director of the Company
|
|
In connection with the conversions of Series A1 Preferred Stock by Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP, the Company entered into transactions with these entities in exchange for cash consideration, promissory notes and cancellation of certain Series A1 Preferred Shares.
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Consideration
|
|
Promissory
Note–Principal
|
|
Series A1 Preferred
Shares Cancelled
|
|
|
Burlingame Equity Investors II, LP
|
|
$
|
4,000
|
|
|
$
|
48,000
|
|
|
|
16
|
|
|
Burlingame Equity Investors Master Fund, LP
|
|
$
|
46,000
|
|
|
$
|
552,000
|
|
|
|
184
|
|
On August 15, 2014, the Company redeemed the remaining 10 shares of Series A-1 Convertible Preferred Stock for consideration of $77,500, of which $15,500 was paid in cash and the remaining amount as a promissory note for $62,000. See additional discussion of the note below in Note 5 – Notes and Advances Payable.
On December 11, 2015, the Company began a private placement of its Series A2 7% Preferred Convertible Stock with a maximum amount of 600 shares at $10,000 per share or $6,000,000. At December 31, 2015, the Company had sold subscriptions equal to $1,750,000 (175 shares) and issued to DNR 90 shares fully paid ($900,000), nonassessable restricted shares of its 7% Series A2 Convertible Preferred Stock as part of the consideration for a settlement agreement entered into with DNR (See Note 5 – Advances and Notes Payable for details of the settlement).
The following are the terms of the Preferred Stock Series A2:
Authorized Shares, Stated Value and Liquidation Preference
. Six hundred shares are designated as the Series A2 7% Convertible Preferred Stock, which has a stated value and liquidation preference of $10,000 per share plus accrued and unpaid dividends.
Ranking
. The Series A2 Preferred Stock will rank senior to future classes or series of preferred stock established after the issue date of the Series A2 Preferred Stock, unless the Company’s Board of Directors expressly provides otherwise when establishing a future class or series. The Series A2 Preferred Stock ranks senior to the Company’s common stock but it is junior to the Company’s outstanding debt and accounts payable.
Dividends
. Holders of Series A2 Preferred Stock are entitled to receive dividends at an annual rate of 7.0% of the $10,000 per share liquidation preference, payable quarterly on each of March 31, June 30, September 30 and December 31. Dividends are payable in cash or in shares of common stock (at its then fair market value), at the Company’s election.
Voting Rights
. Holders of the Series A2 Preferred Stock will vote together with the holders of the Company’s common stock as a single class on all matters upon which the holders of common stock are entitled to vote. Each share of Series A Preferred Stock will be entitled to such number of votes as the number of shares of common stock into which such share of Preferred Stock is convertible; however, solely for the purpose of determining such number of votes, the conversion price per share will be deemed to be $2.00, subject to customary anti-dilution adjustment. In addition, the holders of the Series A2 Preferred Stock will vote as a separate class with respect to certain matters, including amendments to the Company’s Articles of Incorporation that alter the voting powers, preferences and special rights of the Series A2 Preferred Stock.
Liquidation
. In the event we voluntarily or involuntarily liquidate, dissolve or wind up, the holders of the Series A2 Preferred Stock will be entitled, before any distribution or payment out of the Company’s assets may be made to or set aside for the holders of any of the Company’s junior capital stock and subject to the rights of the Company’s creditors, to receive a liquidation distribution in an amount equal to $10,000 per share, plus any unpaid dividends. A merger, consolidation or sale of all or substantially all of the Company’s property or business is not deemed to be a liquidation for purposes of the preceding sentence.
Redemption by the Company
. The Series A2 Preferred Stock is redeemable in whole or in part at the Company’s option at any time for cash. The redemption price is equal to $10,000 per share, plus any unpaid dividends.
Optional Redemption by Holder.
Unless prohibited by Colorado law governing distributions to shareholders, the Company, upon 90 days' prior written request from any holders of outstanding shares of Series A2 Preferred Stock, in its sole discretion, may redeem at a redemption price equal to the sum of (i) $10,000 per share and (ii) the accrued and unpaid dividends thereon, to the redemption date, up to one-third of each holder's outstanding shares of Series A2 Preferred Stock on: (i) the first anniversary of the Original Issue Date (the "
First Redemption Date
"), (ii) the second anniversary of the Original Issue Date (the "
Second Redemption Date
") and (iii) the third anniversary of the Original Issue Date (the "
Third Redemption Date
", along with the First Redemption Date and the Second Redemption Date, collectively, each a "
Redemption Date
"). If on any Redemption Date, Colorado law governing distributions to shareholders prevents the Company from redeeming all shares of Series A2 Preferred Stock to be redeemed, the Company may ratably redeem the maximum number of shares that it may redeem consistent with such law, and may also redeem the remaining shares as soon as it may lawfully do so under such law.
Preemptive Rights
. Holders of the Series A2 Preferred Stock do not have preemptive rights.
Mandatory Conversion
. Each share of Series A2 Preferred Stock remaining outstanding will automatically be converted into shares of the Company’s common stock upon the earlier of (i) any closing of underwritten public offering by us of shares of common stock pursuant to an effective registration statement under the Securities Act of 1933, in which the aggregate cash proceeds to be received by us and selling stockholders (if any) from such offering (without deducting underwriting discounts, expenses and commissions) are at least $7,000,000, and per share sales price is at least $3.00 (such price to be adjusted for any stock dividends, combinations or splits or (ii) the date agreed to by written consent of the holders of a majority of the outstanding Series A2 Preferred Stock.
Optional Conversion by Investors
. At any time, each holder of Series A2 Preferred Stock has the right, at the holder’s option, to convert all or any portion of such holder’s Series A2 Preferred Stock into shares of our common stock at a conversion price of $2.00 per share prior to the mandatory conversion of the Series A2 Preferred Stock.
|
7.
|
Notes and advances payable
|
Notes payable consist of the following as of December 31:
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Officers, directors and affiliates:
|
|
|
|
|
|
|
|
Note payable, interest at 7.5%, due March 2016 (6)
|
|
$
|
150,000
|
|
|
$
|
150,000
|
|
|
Notes payable, interest 7.0%, due January 2019 (3)
|
|
|
63,464
|
|
|
|
79,970
|
|
|
Notes payable, interest varies (4)
|
|
|
-
|
|
|
|
792,151
|
|
|
Collateralized note payable (1)
|
|
|
120,728
|
|
|
|
120,728
|
|
|
|
|
|
|
|
|
|
|
|
|
Total officers, directors and affiliates
|
|
|
334,192
|
|
|
|
1,142,849
|
|
|
Less: Current portion of officers, directors, and affiliates
|
|
|
18,900
|
|
|
|
288,258
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term portion of officers, directors, and affiliates
|
|
$
|
315,292
|
|
|
$
|
854,591
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrelated parties:
|
|
|
|
|
|
|
|
|
|
Notes payable, interest at 7.5%, due March 2016 (7)
|
|
$
|
100,000
|
|
|
$
|
100,000
|
|
|
Note payable, interest variable (see below) due January 2016, Extended to May 2016 (2)
|
|
|
616,105
|
|
|
|
549,105
|
|
|
Note payable, interest at 7.0%, due August 2016 (8)
|
|
|
62,000
|
|
|
|
62,000
|
|
|
Notes payable, interest at 7.0%, due January 2017
|
|
|
32,606
|
|
|
|
41,668
|
|
|
Notes payable, interest at 7.0%, due January 2016, Extended to May 2016 (5)(8)
|
|
|
183,000
|
|
|
|
183,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrelated parties
|
|
|
993,711
|
|
|
|
935,773
|
|
|
Less: Current portion of unrelated parties
|
|
|
970,953
|
|
|
|
872,239
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term portion of unrelated parties
|
|
$
|
22,758
|
|
|
$
|
63,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
On April 29, 2013, the Company executed a promissory note under which the Company agreed to pay Apex Financial Services Corp, a Colorado corporation, (“Apex”) the principal sum of $1,000,000, with interest accruing at an annual rate of 7.5%, with principal and interest due on May 31, 2014, and subsequently extended to March 31, 2017. The Company also agreed to assign 75% of its operating income from its oil and gas operations and any lease or well sale or any other assets sales to Apex to secure the debt. Apex is 100% owned by the CEO, director, and shareholder of the Company, Nicholas L. Scheidt. The Company borrowed the full amount of principal on the note, and also paid a loan fee of $10,000. In the event of default on the note and failure to cure the default in ten days, Apex may accelerate payment and the annual interest rate on the note will accrue at 18%. Default includes failure to pay the note when due or if the Company borrows any other monies or offers security in the Company or in the collateral securing the note prior to the note being paid in full. The outstanding principal balance as of December 31, 2015, was $120,728.
|
|
|
(2)
|
On January 28, 2014, we entered into a line of credit loan agreement for $1,500,000 due January 15, 2015 extended to January 28, 2016, and further extended after December 31, 2015 to May 28, 2016. The terms of the note are as follows: 1) the accrued interest is payable monthly starting February 28, 2014, 2) the interest rate is variable based on an index calculated based on a prime rate as published by the Wall Street Journal index (currently 3.5%) plus an add on index with the current and minimum rate of 6.5%, the note has draw provisions and is secured by seven wells and leases owned by the Company, a certificate of deposit for $500,000 at CityWide Banks pledged by a related party, and 5) the personal guarantee of Nicholas Scheidt, Chief Executive Officer. The amount eligible for borrowing on the Credit Facility is limited to the lesser of (i) 65% of the Company’s PV10 value of its carbon reserves based upon the most current engineering reserve report or (ii) 48 month cumulative cash flow based upon the most current engineering reserve report. In addition to the borrowing base limitation, the Company is required to maintain and meet certain affirmative and negative covenants and conditions in order to draw advances on the Credit Facility. The Credit Facility contains certain representations, warranties, and affirmative and negative covenants applicable to the Company, which are customarily applicable to senior secured loan facilities. Key covenants include limitations on indebtedness, restricted payments, creation of liens on oil and gas properties, hedging transactions, mergers and consolidations, sales of assets, use of loan proceeds, change in business, and change in control. The above-referenced promissory note contains customary default and acceleration provisions and provides for a default interest rate of 21% per annum. In addition, the Credit Facility contains customary events of default, including: (a) failure to pay any obligations when due; (b) failure to comply with certain restrictive covenants; (c) false or misleading representations or warranties; (d) defaults of other indebtedness; (e) specified events of bankruptcy, insolvency or similar proceedings; (f) one or more final, non-appealable judgments in excess of $50,000 that is not covered by insurance; (g) change in control (25% threshold); (h) negative events affecting the Guarantor; and (i) lender in good faith believes itself insecure. In an event of default arising from the specified events, the Credit Facility provides that the commitments thereunder will terminate and the Lender may take such other actions as permitted including, declaring any principal and accrued interest owed on the line of credit to become immediately due and payable. The Credit Facility is secured by a security interest in substantially all of the assets of the Company, pursuant to a Security Agreement, Deed of Trust and Assignment of As-Extracted Collateral entered into between the Company and Citywide Banks. The outstanding principal balance as of December 31, 2015 was $616,105.
|
|
|
(3)
|
On January 1, 2014, we memorialized certain short-term liabilities into formal promissory notes. Information concerning these promissory notes is set forth in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Position
|
Principal Amount
|
|
Annual Interest Rate
|
|
Monthly P&I
Payment
Amount
|
|
Number
of
Monthly
Payments
|
|
|
Donald W. Prosser
|
Former CFO & Director
|
|
$
|
28,500
|
|
|
|
7.00
|
%
|
|
$
|
564
|
|
|
|
60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Charles B. Davis
|
COO & Director
|
|
$
|
66,500
|
|
|
|
7.00
|
%
|
|
$
|
1,317
|
|
|
|
60
|
|
The above-referenced promissory notes contain customary default and acceleration provisions and provide for a default interest rate of 18% per annum. The aggregate outstanding principal balance on the notes as of December 31, 2015 was $63,464.
|
|
(4)
|
We issued an unsecured promissory note in the amount of $792,151 on January 1, 2014 to DNR. The note accrues interest at the rate of 2.50% for the calendar years 2014 and 2015, 4.00% for the calendar year 2016, 6.00% for the calendar year 2017 and 8.00% for the remainder of the term of the DNR note. The DNR note matures on January 1, 2019.
|
On January 19, 2016, but effective December 31, 2015, (the "Effective Date") we entered into a Settlement Agreement with DNR and Tindall Operating Company discussed above under which the DNR Note was deemed paid in full.
|
|
(5)
|
In June 2013, in connection with the conversions of Series A1 Preferred Stock by Burlingame Equity Investors II, LP and Burlingame Equity Investors Master Fund, LP, the Company issued unsecured promissory notes in the original principal amounts of $48,000 and $552,000, respectively, with interest at 7% per annum payable quarterly and all unpaid interest and principal due on July 23, 2014. We have agreed with the holders of these two existing notes to extend the maturity date of the notes to May 25, 2016. Information concerning the principal pay down is set forth in the following table.
|
|
|
|
Principal Balance
before Pay down
|
|
|
Principal
Pay down
|
|
|
Remaining
Principal Balance
|
|
|
Burlingame Equity Investors II, LP
|
|
$
|
44,000
|
|
|
$
|
26,251
|
|
|
$
|
17,749
|
|
|
Burlingame Equity Investors Master Fund, LP
|
|
$
|
506,000
|
|
|
$
|
340,749
|
|
|
$
|
165,251
|
|
|
|
(6)
|
On March 28, 2012, the Company executed a Promissory Note with Fairfield Management Group, LLC (“Fairfield”), a related party. The note accrues interest at 7.5%, payable monthly and has a maturity date of March 31, 2016. During the fiscal year ended December 31, 2015, Fairfield assigned this note to Donald Prosser (former CFO and Director). Subsequent to the year ended December 31, 2015, the Company and Mr. Prosser extended the due date to March 31, 2017.
|
|
|
(7)
|
On March 28, 2012, the Company executed a promissory note with Pikerni, LLC (“Pikerni”). This note was extended and amended on April 1, 2015. The note accrues interest at 7.5% and is payable quarterly. The maturity date of the note is April 1, 2016, with principal payments of $5,000 due on June 30, 2015, September 30, 2015, December 31, 2015, and March 31, 2016, and the remaining principal balance of $80,000 due on April 1, 2016. At December 31, 2015, the Company was in default on this note. The Company is currently negotiating an amendment with Pikerni to cure the default.
|
|
|
(8)
|
On August 15, 2014, the Company redeemed the remaining 10 shares of Series A-1 Convertible Preferred Stock outstanding for consideration of $77,500, of which $15,500 was paid in cash and the remaining amount as a promissory note for $62,000. The note accrues interest at 7% per annum, payable in two installments as follows;
|
|
|
a.
|
A payment of $31,000, plus accrued and unpaid interest was payable on August 15, 2015
|
|
|
b.
|
A payment of $31,000, plus accrued and unpaid interest shall be payable on August 15, 2016
|
The Company did not make the August 15, 2015, principal payment and is currently in default on this note. The Company is negotiating new terms with the note holder.
|
8.
|
General and Administrative Expenses
|
In connection with the property acquisition agreement entered into in the third quarter of 2011, the Company executed an operating agreement whereby DNR provides services to operate all of the properties acquired by the Company for a monthly fee of $23,000. The operating agreement expired on March 31, 2012 and renews on a month to month basis.
Based on operator costs for the properties prior to the Company’s acquisition, approximately $8,000 per month was classified as lease operating expenses and $15,000 per month was classified as related party consulting fees. Effective July 1, 2012, the monthly operator fee was reduced to $18,000 per month, of which $8,000 per month is included in lease operating expense and the remaining $10,000 per month is included in related party consulting fees in the consolidated statements of operations.
Presented below is a summary of general and administrative expenses for the years ended December 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Change
|
|
|
Director fees
|
|
$
|
47,833
|
|
|
$
|
20,450
|
|
|
$
|
27,383
|
|
|
Investor relations
|
|
|
28,128
|
|
|
|
65,833
|
|
|
|
(37,705
|
)
|
|
Legal, auditing and professional services
|
|
|
116,078
|
|
|
|
146,581
|
|
|
|
(30,503
|
)
|
|
Consulting and executive services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Related parties
|
|
|
172,217
|
|
|
|
220,800
|
|
|
|
(48,583
|
)
|
|
Unrelated parties
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Other administrative expenses
|
|
|
74,634
|
|
|
|
72,807
|
|
|
|
1,827
|
|
|
Depreciation
|
|
|
428
|
|
|
|
570
|
|
|
|
(142
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses
|
|
$
|
439,318
|
|
|
$
|
527,041
|
|
|
$
|
(87,723
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2015, the Company has net operating loss (“NOL”) carryforwards for Federal income tax purposes of approximately $8,336,000. If not previously utilized, the NOL carryforwards will expire in 2018 through 2035.
For the years ended December 31, 2015 and 2014, the Company did not recognize any current or deferred income tax benefit or expense. Actual income tax benefit (expense) for the years ended December 31, 2015 and 2014 differs from the amounts computed using the federal statutory tax rate of 34%, as follows:
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Income tax benefit (expense) at the statutory rate
|
|
$
|
1,614,000
|
|
|
$
|
(21,000
|
)
|
|
Benefit (expense) resulting from:
|
|
|
|
|
|
|
|
|
|
Increase in Federal valuation allowance
|
|
|
(1,884,000
|
)
|
|
|
—
|
|
|
Other permanent differences
|
|
|
270,000
|
|
|
|
—
|
|
|
Utilization of net operating loss carryforwards
|
|
|
—
|
|
|
|
21,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2015 and 2014, the tax effects of temporary differences that give rise to significant deferred tax assets and liabilities are presented below:
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Federal net operating loss carryforwards
|
|
$
|
3,030,000
|
|
|
$
|
2,465,000
|
|
|
State net operating loss carryforwards
|
|
|
315,000
|
|
|
|
264,000
|
|
|
Oil and gas properties
|
|
|
917,000
|
|
|
|
(222,000
|
)
|
|
Asset retirement obligations
|
|
|
371,000
|
|
|
|
241,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
4,632,000
|
|
|
|
2,748,000
|
|
|
Less valuation allowance
|
|
|
(4,632,000
|
)
|
|
|
(2,748,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
A valuation allowance has been recorded for all deferred tax assets since the “more likely than not” realization criterion was not met as of December 31, 2015 and 2014.
A tax benefit from an uncertain tax position may be recognized if it is “more likely than not” that the position is sustainable based solely on its technical merits. For the years ended December 31, 2015 and 2014, the Company had no unrecognized tax benefits and management is not aware of any issues that would cause a significant increase to the amount of unrecognized tax benefits within the next year. The Company’s policy is to recognize any interest or penalties as a component of income tax expense. The Company’s material taxing jurisdictions are comprised of the U.S. federal jurisdiction and the states of Colorado, Wyoming and Kansas. The tax years 2010 through 2015 remain open to examination by these taxing jurisdictions.
|
10.
|
Asset Retirement Obligations
|
The Company follows accounting for asset retirement obligations (“ARO”) in accordance with ASC 410,
Asset Retirement and Environmental Obligations
, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value can be made. The Company’s ARO primarily represents the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its ARO by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The ARO is accreted to its present value each period and the capitalized asset retirement costs are amortized using the unit of production method.
A reconciliation of the Company’s ARO for the years ended December 31, 2015 and 2014 is as follows:
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Balance, beginning of year
|
|
$
|
749,013
|
|
|
$
|
682,203
|
|
|
Liabilities incurred upon acquisition of properties
|
|
|
204,493
|
|
|
|
—
|
|
|
Liabilities settled
|
|
|
(28,684
|
)
|
|
|
—
|
|
|
Accretion expense
|
|
|
70,375
|
|
|
|
66,810
|
|
|
Revisions of prior estimates
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
|
995,197
|
|
|
|
749,013
|
|
|
Less current asset retirement obligations
|
|
|
(409,621
|
)
|
|
|
(191,843
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Long-term asset retirement obligations
|
|
$
|
585,576
|
|
|
$
|
557,170
|
|
|
|
|
|
|
|
|
|
|
|
|
11.
|
Commitments and Contingencies
|
Lease commitments.
The Company entered into a lease for property access rights and compressor space in Wyoming related to the Company’s natural gas gathering system. The expense in 2015 and 2014 was approximately $1,400 and $9,000, which is included in gas gathering operating costs. The Company used office space and conference room space provided by a director for an annual charge of $3,000 for the year ended December 31, 2014. The Company does not have any operating leases in place at December 31, 2015.
Legal Proceedings.
The Company is subject to the risk of litigation, claims and assessments that may arise in the ordinary course of its business activities, including contractual matters and regulatory proceedings. As of December 31, 2015, the Company was not subject to any pending litigation and management is not currently aware of any asserted or unasserted claims and assessments that may impact the Company’s future results of operations.
The following are the subsequent events:
The Company extended the following notes subsequent to the year ended December 31, 2015;
|
|
·
|
Donald W. Prosser (formerly Fairfield) - $100,000 principal – extended to March 31, 2017
|
|
|
·
|
Apex Financial Services Corp.- $120,728 principal– extended to March 31, 2017
|
|
|
·
|
CityWide Banks - $616, 105 principal– extended to May 28, 2016
|
|
|
·
|
Burlingame Equity Investors II, LP – extended to May 25, 2016
|
|
|
·
|
Burlingame Equity Investors Master Fund, LP – extended to May 25, 2016
|
(See Note 7.)
|
13.
|
Supplementary Oil and Gas Information (unaudited)
|
Costs Incurred in Oil and Gas Producing Activities
Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion, depreciation, amortization and accretion (“DD&A”) per equivalent unit-of-production were as follows for the years ended December 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Acquisition costs:
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
—
|
|
|
$
|
34,500
|
|
|
Proved properties
|
|
|
1,404,493
|
|
|
|
—
|
|
|
Exploration costs
|
|
|
—
|
|
|
|
—
|
|
|
Development costs
|
|
|
115,992
|
|
|
|
594,359
|
|
|
Revisions to asset retirement obligation
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
1,520,485
|
|
|
$
|
628,859
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion per BOE of production
|
|
$
|
27.78
|
|
|
$
|
22.24
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Oil and Gas Reserve Information
The reserve information presented below is based on estimates of net proved reserves as of December 31, 2015 and 2014 that were prepared by Pinnacle Energy Services, L.L.C. and Ryder Scott Company, respectively, the Company’s independent petroleum engineering firms, in accordance with guidelines established by the SEC.
Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Changes in Proved Reserves
The following table sets forth information regarding the Company’s estimated total proved and oil and gas reserve quantities for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Bbl)
|
|
|
Gas
(Mcf)
|
|
|
Equivalent
(BOE)
|
|
|
Balance, January 1, 2014
|
|
|
246,994
|
|
|
|
676,788
|
|
|
|
359,792
|
|
|
Sale of oil and gas reserves in place
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Revisions in previous estimates
|
|
|
13,060
|
|
|
|
8,347
|
|
|
|
14,452
|
|
|
Production
|
|
|
(22,825
|
)
|
|
|
(70,195
|
)
|
|
|
(34,524
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2014
|
|
|
237,229
|
|
|
|
614,940
|
|
|
|
339,720
|
|
|
Sale of oil and gas reserves in place
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Acquisition of reserves in place
|
|
|
71,870
|
|
|
|
—
|
|
|
|
71,870
|
|
|
Revisions in previous estimates
|
|
|
(14,924
|
)
|
|
|
(194,070
|
)
|
|
|
(47,269
|
)
|
|
Production
|
|
|
(18,955
|
)
|
|
|
(62,630
|
)
|
|
|
(29,393
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2015
|
|
|
275,220
|
|
|
|
358,240
|
|
|
|
334,928
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, December 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed
|
|
|
230,530
|
|
|
|
614,940
|
|
|
|
333,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped
|
|
|
6,699
|
|
|
|
—
|
|
|
|
6,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, December 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed
|
|
|
275,220
|
|
|
|
358,240
|
|
|
|
334,928
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure
Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.
As of December 31, 2014, future cash inflows were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December of 2014, which resulted in benchmark prices of $94.99 per barrel for crude oil and $4.35 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2014, of $84.09 per barrel of oil and $6.09 per Mcf for natural gas.
As of December 31, 2015, future cash inflows were computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December of 2015, which resulted in benchmark prices of $50.28 per barrel for crude oil and $2.587 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in a difference from the benchmark prices ranging from -$3.40 per barrel to -$10.77 per barrel, depending on the location of the wells. The calculated natural gas differentials ranged from -81% to +59% as a percentage of the benchmark prices depending on where the well was located.
The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Net operating losses incurred in oil and gas producing activities are utilized to reduce taxable income. Permanent differences in oil and gas related tax credits and allowances are recognized, if reasonably estimable.
A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves as of December 31, 2013 and 2014:
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Future cash inflows
|
|
$
|
13,002,030
|
|
|
$
|
23,132,987
|
|
|
Future production costs
|
|
|
(7,976,560
|
)
|
|
|
(9,732,541
|
)
|
|
Future development costs
|
|
|
—
|
|
|
|
(781,442
|
)
|
|
Future income taxes
|
|
|
—
|
|
|
|
(1,905,627
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
5,025,470
|
|
|
|
10,713,377
|
|
|
10% annual discount
|
|
|
(2,472,800
|
)
|
|
|
(4,724,250
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
2,552,670
|
|
|
$
|
5,989,127
|
|
|
|
|
|
|
|
|
|
|
|
The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil and gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on average prices realized in the preceding year and on costs in effect at the end of the year. However, actual future net cash flows from the Company’s oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas and changes in governmental regulations or taxation.
The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.
A summary of changes in the standardized measure of discounted future net cash flows is as follows for the years ended December 31, 2013 and 2014:
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Standardized measure of discounted future net cash flows, beginning of year
|
|
$
|
5,989,127
|
|
|
$
|
6,154,647
|
|
|
Sales of oil and gas, net of production costs and taxes
|
|
|
23,891
|
|
|
|
(1,190,850
|
)
|
|
Purchases of reserves in place
|
|
|
589,190
|
|
|
|
—
|
|
|
Sales of reserves in place
|
|
|
—
|
|
|
|
—
|
|
|
Changes in development costs
|
|
|
(699,000
|
)
|
|
|
98,054
|
|
|
Revisions of previous estimates
|
|
|
(440,871
|
)
|
|
|
213,112
|
|
|
Changes in prices and production costs
|
|
|
(4,661,912
|
)
|
|
|
(341,335
|
)
|
|
Net changes in income taxes
|
|
|
1,153,332
|
|
|
|
440,034
|
|
|
Accretion of discount
|
|
|
598,913
|
|
|
|
615,465
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows, end of year
|
|
$
|
2,552,670
|
|
|
$
|
5,989,127
|
|
|
|
|
|
|
|
|
|
|
|