NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1
- ORGANIZATION
Glori Energy Technology Inc., a Delaware corporation (formerly Glori Energy Inc.) ("GETI"), was incorporated in November 2005 (as successor in interest to Glori Oil LLC) to increase production and recovery from mature oil wells using state of the art biotechnology solutions.
In January 2014, GETI entered into a merger and share exchange agreement with Infinity Cross Border Acquisition Corporation ("INXB") and certain of its affiliates, Glori Acquisition Corp., Glori Merger Subsidiary, Inc., and Infinity-C.S.V.C. Management Ltd., an INXB Representative. On April 14, 2014, the merger and share exchange agreement was closed and the merger was consummated. As a result of this transaction, Infinity Cross Border Acquisition Corporation merged with and into Glori Acquisition Corp., with Glori Acquisition Corp. surviving the merger. Following that merger, Glori Merger Subsidiary, Inc. merged with and into GETI, with GETI surviving the merger. Following both of these mergers (collectively referred to herein as the "Merger"), GETI became the wholly-owned subsidiary of Glori Acquisition Corp., and Glori Acquisition Corp. adopted the name "Glori Energy Inc."
In March 2014, GETI incorporated Glori Energy Production Inc. ("GEP"), a wholly-owned subsidiary of Glori Holdings Inc., to purchase the Coke Field Assets (see
NOTE 5
) and incur the associated acquisition debt.
The dissolution of Glori Oil S.R.L and Glori Oil (Argentina) Limited were effective on August 24, 2015. During the year ended December 31, 2014 and 2015 there were no revenues and no assets associated with Glori Oil S.R.L and Glori Oil (Argentina) Limited.
Glori Energy Inc., GETI, Glori Canada Ltd., Glori Holdings Inc., Glori California Inc., OOO Glori Energy and Glori Energy Production Inc. are collectively referred to as the “Company” in the consolidated financial statements.
NOTE 2
– SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Glori Energy Inc. and its wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Cash and Cash Equivalents
The Company considers all highly liquid investments with original maturities of three months or less when purchased to be cash equivalents.
Concentrations of Credit Risk
The Company maintains its cash in bank deposits with financial institutions. These bank deposits, at times, exceed Federal Deposit Insurance Corporation limits of
$250,000
per depositor. The Company monitors the financial condition of the financial institutions and has not experienced any losses on such accounts. The Company is not party to any financial instruments which would have off-balance sheet credit or interest rate risk.
The Company derived service revenues from
fifteen
customers during
2014
, and
four
customers during
2015
. The following is a reconciliation of the customers that exceeded
10%
of total service revenues in each of those periods:
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|
|
|
|
|
|
|
|
|
|
|
|
Percentage of service revenues
Year ended December 31,
|
|
Customer
|
|
2014
|
|
2015
|
|
A
|
|
36
|
%
|
|
—
|
|
|
B
|
|
17
|
%
|
|
20
|
%
|
|
C
|
|
10
|
%
|
|
65
|
%
|
|
D
|
|
10
|
%
|
|
—
|
|
Management does not believe that these customers constitute a significant credit risk.
The Company had outstanding receivables related to service revenues from
four
customers as of
December 31, 2014
and
one
customer as of
December 31, 2015
. The following is a reconciliation of the customers that exceeded
10%
of total accounts receivable from service revenues as of each of these dates:
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|
|
|
|
|
|
|
|
|
|
Percentage of outstanding
accounts receivable from service revenues December 31,
|
|
Customer
|
|
2014
|
|
2015
|
|
C
|
|
—
|
|
100%
|
|
D
|
|
19%
|
|
—
|
|
E
|
|
54%
|
|
—
|
|
F
|
|
27%
|
|
—
|
Oil and natural gas sales are made on a monthly basis or under short-term contracts at the current area market price. The Company would not expect that the loss of any purchaser would have a material adverse effect upon its operations. Additionally, management does not believe any of our purchasers constitute a significant credit risk. For the
year ended December 31, 2014
there were
two
purchasers that accounted for
57%
and
39%
of total oil revenue. For the
year ended December 31, 2015
there was one purchaser that accounted for
93%
of the total oil revenue. The Company sells its natural gas to a different purchaser than that of its oil sales. Natural gas sales did not exceeded 10% of total oil and gas revenues for the years ended
year ended December 31, 2014
and
2015
.
As of
December 31, 2014
and
2015
, the Company had a $
900,000
and
$436,000
receivable, respectively, for December oil sales from a single oil purchaser.
The Company also engages in NYMEX swaps with a third party company (see
NOTE 9
).
Accounts Receivable
Accounts receivable consists of amounts due in the ordinary course of business, from companies engaged in the exploration of oil and gas and from third party purchasers of the Company's oil and natural gas production. The Company performs ongoing credit evaluation of its customers and generally does not require collateral. Allowances are maintained for potential credit issues as they arise through management’s analysis of factors such as amount of time outstanding, customer payment history and customer financial condition. The Company has incurred inconsequential credit losses since inception. As of
December 31, 2014
and
December 31, 2015
the Company had
no
allowance for doubtful accounts.
Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for oil and gas operations whereby the cost to acquire mineral investments in oil and gas properties, to drill successful exploratory wells, to drill and equip development wells and to install production facilities are capitalized. Certain exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. The Company’s acquisition and development costs of proved oil and gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves as estimated by independent petroleum engineers.
Other Property and Equipment
Property and equipment are recorded at cost. Expenditures for major additions and improvements are capitalized and depreciated over the remaining useful lives of the associated assets, and repairs and maintenance costs are charged to expense as incurred.
When property and equipment are retired or otherwise disposed, the cost and accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in the results of operations for the respective period.
Depreciation and amortization for long-lived assets are recognized over the estimated useful lives of the respective assets by the straight-line method as follows:
|
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|
|
Laboratory and manufacturing facility
|
|
5 years or the remaining term of the lease, whichever is shorter
|
|
|
|
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|
Laboratory and field service equipment, office equipment and trucks
|
|
5 years
|
|
|
|
|
|
Computer equipment
|
|
3 years
|
Impairment of Long-Lived Assets
The Company reviews the recoverability of its long-lived assets, such as property, equipment and oil and gas properties, periodically and when events or changes in circumstances occur that indicate the carrying value of the asset or asset group may not be recoverable. The initial assessment of possible impairment is based on the Company’s ability to recover the carrying value of the asset or asset group from the expected future pre-tax cash flows (undiscounted) of the related operations. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis for oil and gas properties. If these cash flows are less than the carrying value of such asset, an impairment loss is recognized for the difference between estimated fair value and carrying value.
The Company impaired its proved-oil and gas properties for the fiscal years ended
December 31, 2014
and
2015
. To determine the remaining value of the net assets, the Company typically uses a discounted future cash flow approach based on the proved and probable reserves at estimated future commodities prices less regional discounts to calculate the value of the reserves at fiscal year-end. At December 31, 2015 there was no economic value assigned to any proved undeveloped reserves. The Company believes this estimate to approximate fair value. The impairments in 2014 and
2015
were a result of a sharp decline in oil prices. The reduction in asset value of proved oil and gas properties of $
13,160,000
and $
22,600,000
represents the impairment amounts incurred in
2014
and
2015
, respectively, which are shown as impairment of oil and gas properties on the consolidated statement of operations.
Derivatives
The Company uses derivative instruments in the form of commodity price swaps to manage price risks resulting from fluctuations in commodity prices of oil associated with future production. These derivative instruments are recorded on the balance sheet at fair value as assets or liabilities and the changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining the NYMEX futures oil commodity pricing. Gains and losses on the valuation of derivatives and settlement of matured commodity derivatives contracts are included in gain (loss) on commodity derivatives in other income within the period in which they occur.
Asset Retirement Obligation
The Company recognizes the present value of the estimated future abandonment costs of its oil and gas properties in both assets and liabilities. If a reasonable estimate of the fair value can be made, the Company will record a liability for legal obligations associated with the future retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of the assets. The fair value of a liability for an asset retirement obligation is recognized in the period in which the liability is incurred. The fair value is measured using expected future cash outflows (estimated using current prices that are escalated by an assumed inflation rate) discounted at the Company’s credit-adjusted risk-free interest rate. The liability is then accreted each period until it is settled or the asset is sold, at which time the liability is reversed and any gain or loss resulting from the settlement of the obligation is recorded. The initial fair value of the asset retirement obligation is capitalized and subsequently depreciated or amortized as part of the carrying amount of the related asset. The Company has recorded asset retirement obligations related to its oil and gas properties. There are
no
assets legally restricted for the purpose of settling asset retirement obligations.
Financial Instruments
Financial instruments consist of cash and cash equivalents, accounts receivable, accounts payables, long-term debt, derivatives, and warrants. The carrying values of cash and cash equivalents and accounts receivable and payables approximate fair value due to their short-term nature. Derivatives are recorded at fair value (see
NOTE 8
and
NOTE 9
).
Net Loss Per Share
Basic net loss per share is computed using the weighted-average number of shares of common stock outstanding during the period. In periods that have income, basic net earnings per common share is computed under the two-class method per guidance in Accounting Standards Codification (ASC) 260,
Earnings per Share
. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Under the two-class method, basic earnings per common share is computed by dividing net earnings attributable to common shares after allocation of earnings to participating securities by the weighted-average number of common shares outstanding during the year. However, in periods of net loss, participating securities other than common stock are not included in the calculation of basic loss per share because there is no contractual obligation for owners of these securities to share in the Company’s losses, and the effect of their inclusion would be anti-dilutive. Diluted earnings (loss) per common share is computed using the two-class method or the if-converted method, whichever is more dilutive (see
NOTE 11
).
Diluted net loss per share is the same as basic net loss per share for all periods presented because any potentially dilutive common shares were anti-dilutive. Such potentially dilutive shares are excluded from the computation of diluted net loss per share when the effect would be to reduce net loss per share. Therefore, in periods when a loss is reported, the calculation of basic and diluted loss per share results in the same value.
Revenue Recognition
Oil and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Revenues from natural gas production are recorded using the sales method.
Service revenues are recognized when all services are concluded in accordance with the contract. The Company’s service contracts typically include a single contract for each phase of service. During the initial phase known as Reservoir Analysis and Treatment Design (the “Analysis Phase”), the Company samples the target field and evaluates project feasibility and nutrient formulation by assessing field characteristics such as geology, microbial environment and geochemistry of the oil and water. The completion of the Analysis Phase contract typically coincides with the delivery of a report of findings to the customer at which point the Analysis Phase revenues are recognized. Once the viability of the AERO System is demonstrated in the Analysis Phase, a new contract is executed for the Field Deployment Phase. During the Field Deployment Phase the AERO System is initiated in the oil field to stimulate the indigenous microbes in the oil bearing reservoir. The Field Deployment Phase revenues are recognized ratably over the Field Deployment Phase injection work timeline.
Previous to 2014, the majority of the Company’s revenues for AERO services were executed under a single contract which covered both Analysis Phase and Field Deployment Phase work. The single contract for both services resulted in lack of commercial evidence that the Analysis Phase services provided value on a stand-alone basis and thus both services were viewed as a single unit-of-accounting under
ASC 605, Revenue Recognition: Multiple-Element Arrangements
. In accordance with this guidance, the Company deferred revenue received in the Analysis Phase and recognize this revenue and the Field Deployment Phase revenue uniformly over the Field Deployment Phase injection timeline. Any termination of the project after the completion of the Analysis Phase would result in the immediate recognition of that portion of the revenues outlined in the contract.
As of
December 31, 2014
and
2015
, the Company had deferred revenues of approximately
$653,000
and
$0
respectively, pursuant to contracts requiring substantial future performance.
Science and Technology
The Company expenses all science and technology costs as incurred. The science and technology work performed predominantly relates to the Analysis Phase and the expenses are primarily made up of employee compensation, lab supplies and materials, legal fees and corporate overhead allocations.
Income Taxes
The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and to net operating loss carry forwards, measured by enacted tax rates for years in which taxes are expected to be paid, recovered or settled. A valuation allowance is established to reduce deferred tax assets if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
The Company follows ASC 740,
Income Taxes
(“ASC 740”), which creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the consolidated financial statements.
The Company’s tax years 2006 through
2015
remain open and subject to examination by the Internal Revenue Service (“IRS”) and are open for examination until the expiration of statute of limitations under the IRS Code.
Stock-Based Compensation
The Company has issued stock options, restricted shares, performance based options and market based options. The Company records share-based payment expense associated with option awards in accordance with ASC 718,
Compensation - Stock Compensation
. Accordingly, the Company selected the Black-Scholes option-pricing model as the most appropriate method to value option awards and recognizes compensation cost, as determined on the grant date, on a straight-line basis over the option awards’ vesting period. Stock-based compensation cost for restricted shares is estimated at the grant date based on the awards' fair value, which is equal to the prior day's closing stock price. Such fair value is recognized as expense over the requisite service period.
Fair Value of Financial Instruments
FASB standards define fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The standard also establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three levels of inputs that may be used to measure fair value:
Level 1 – Quoted prices in active markets for identical assets or liabilities.
Level 2 – Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; or other inputs that are observable or can be corroborated by observable market data.
Level 3 – Unobservable inputs that are supported by little or no market activity and that are financial instruments whose values are determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant judgment or estimation.
If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.
Accounting for Sales Tax
The Company uses the net method for accounting for sales taxes charged to customers and accordingly does not include sales or similar taxes as revenues; the Company does include sales and similar taxes paid as part of the cost of goods or services acquired.
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (FASB) and the International Accounting Standards Board (IASB) issued a comprehensive new revenue recognition standard that will supersede existing revenue recognition guidance under United States generally accepted accounting principles (U.S. GAAP) and International Financial Reporting Standards (IFRS). The issuance of this guidance completes the joint effort by the FASB and the IASB to improve financial reporting by creating common revenue recognition guidance for U.S. GAAP and IFRS.
The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard’s application impact to individual financial statement line items.This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We are currently evaluating this standard and the impact it will have on our future revenue recognition policies.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15: Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (ASU 2014-15). ASU 2014-15 asserts that management should evaluate whether there are relevant condition or events that are known and reasonably knowable that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the financial statements are issued or are available to be issued when applicable. If conditions or events at the date the financial statements are issued raise substantial doubt about an entity’s ability to continue as a going concern, disclosures are required which will enable users of the financial statements to understand the conditions or events as well as management’s evaluation and plan. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter; early application is permitted. We are currently evaluating this standard and the impact it will have on our consolidated financial statements.
In April 2015, the FASB issued ASU No. 2015-03, "Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs" (ASU 2015-03). ASU 2015-03 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015 and early adoption is permitted. Prior GAAP guidance mandates recognizing debt issuance costs as a deferred charge. Such treatment is different from the guidance in International Financial Reporting Standards (IFRS),
which requires that transaction costs be deducted from the carrying value of the financial liability and not recorded as separate assets. Additionally, the requirement to recognize debt issuance costs as deferred charges conflicts with the guidance in FASB Concepts Statement No. 6, Elements of Financial Statements, which states that debt issuance costs are similar to debt discounts and in effect reduce the proceeds of borrowing, thereby increasing the effective interest rate. Concepts Statement 6 further states that debt issuance costs cannot be an asset because they provide no future economic benefit. To simplify presentation of debt issuance costs, the amendments in this Update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this Update. We are currently evaluating this standard and the impact it will have on our consolidated financial statements.
In November 2015, the FASB issued Accounting Standards Update No. 2015-17: Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17). ASU 2015-17 is part of an initiative to reduce complexity in accounting standards. Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. However, this classification does not generally align with the time period in which the recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of the deferred income taxes, ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The current requirement that deferred tax liabilities and assets of an entity be offset and presented as a single amount is not affected by the amendments of ASU 2015-17. For public entities, ASU 2015-17 is effective for financial statements issued for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years; early application is permitted. The provisions of this accounting update are not anticipated to have a material impact on the Company’s financial position or results of operations.
Reclassifications
Certain 2014 amounts related to inventory and prepaid expenses and other current assets have been reclassified for comparative purposes.
NOTE 3
- RISKS AND UNCERTAINTIES
As a small company with an emerging technology the Company has generated negative cash flows since inception. The Company continues to generate negative cash flows and the downturn in the oil market has adversely affected its results from operations and cash flows. Cash has decreased from
$29.8 million
at December 31, 2014 to
$8.4 million
at December 31, 2015 due to the net cash used in operating activities of
$9.7 million
, the repayment of debt of
$8.8 million
net, and capital expenditures of
$3.0 million
, net of the proceeds from the sale of the long-term derivatives of
$2.7 million
. As of December 31, 2015 the Company has working capital of
$9.3 million
. Based on its cash balance and forecasted cash flows from operating activities, the Company expects to be able to fund planned capital expenditures, meet debt service requirements, and fund other commitments and obligations for 2016.
As of March 21, 2015, the Company does not have lines of credit available to it. As a result of the negative cash flows and the decrease in oil prices, the Company will likely need to raise capital over the next twelve months to fund its operations and to repay or refinance its term note of
$10.5 million
which matures March of 2017. The Company may have difficulty obtaining such additional financing as a result of the decrease in oil prices, its negative cash flows from operations and the significant decrease in its share price. Failure to obtain additional financing would have a material adverse effect on the Company’s business operations and financial condition.
On October 23, 2015, the Company received a deficiency letter (the “Notice Letter”) from The NASDAQ Stock Market LLC (“NASDAQ”) indicating that the Company’s common stock for the last 30 consecutive business days had closed below the minimum
$1.00
per share requirement under NASDAQ Listing Rule 5550(a)(2) (the “Minimum Bid Price Requirement”). The Notification Letter states that Glori has
180
calendar days, until April 20, 2016 (the “Initial Compliance Period”), to regain compliance with the Minimum Bid Price Requirement. In accordance with NASDAQ Listing Rule 5810(c)(3)(A), the Company can regain compliance if the closing bid price of its common stock is at least
$1.00
for a minimum of
10
consecutive business days. If the Company does not achieve compliance with the Minimum Bid Price Requirement by the end of the Initial Compliance Period, it may be granted a second
180
day compliance period, as long as (a) on the last day of the Compliance Period the Company is in compliance with the market value requirement for continued listing as well as all other listing standards and (b) the Company provides written notice of its intention to cure the deficiency during a second compliance period.
The significant decrease in oil prices has made it difficult for the Company to execute on its strategy of acquiring producing properties which would contribute to its revenues and cash flows due to potential sellers’ reluctance to sell at depressed prices. Additionally, the current oil price environment has negatively affected the Company's cash flow and has affected the availability of capital to Glori and the E&P industry in general. These factors have also resulted in a dramatic decrease in the Company's stock price, which also impacts the ability to raise new equity capital.
In order to address this challenging environment, the Company has retained a financial advisory firm with experience in the energy industry to actively explore alternatives for mergers and acquisitions with potential partners, investors and asset sellers with the goal of bolstering its liquidity and enabling the Company to build a larger asset base. Additionally, the Company made significant cost reductions, both in its administrative and professional staff, and lease operating expenses. The cost reductions were implemented both in 2015 and in the first quarter of 2016. The Company also limited capital expenditures to those required to fully implement AERO technology at the Coke field. The Company believes demonstrated AERO technology results at the Coke field will enhance revenues and cash flows and will improve its ability to raise additional capital. In August 2015, the Company implemented the first phase of AERO at the Coke field. In March 2016 it completed installation of phase II of AERO implementation. Phase II incorporates the addition of
two
AERO injection wells to increase the proportion of the field that is impacted by AERO technology. The Company now has
three
injection wells running in total. Phase II implementation commenced after data from Phase I limited trial demonstrated encouraging indication of AERO performance. The wells are located on the periphery of the Coke field and are designed to stimulate production from more of the field than was impacted by the first injector.
Finally, the Company applied to the United States Department of Energy’s Loan Programs Office (“LPO”) for a
$150 million
loan guarantee in connection with a project applying AERO to previously abandoned reservoirs in the U. S. Based on LPO’s evaluation of Part I of the application, in March 2016, LPO invited the Company to submit Part II of its application. However, the ultimate outcome of the application and whether a loan guarantee will be issued cannot be predicted.
On March 18, 2016, GEP entered into an amendment to the credit agreement on the senior secured term loan facility with its lender, Stellus Capital Investment Corporation, which had the effect of removing the financial ratio covenants and the semi-annual collateral value redetermination until maturity in March 2017 (see
NOTE 10
). Without this amendment the Company likely would not have been able to meet all financial covenants in the future.
NOTE 4
- MERGER WITH INFINITY CROSS BORDER ACQUISITION CORPORATION
On January 8, 2014, GETI executed the Merger with Infinity Cross Border Acquisition Corporation (“Infinity Corp.” - a special purpose acquisition company or blank check company publicly traded on NASDAQ) and certain of its affiliates. On April 14, 2014, the Merger was consummated. Pursuant to the terms of the Merger, in exchange for all of GETI's outstanding shares and warrants, Infinity Corp. issued
23,584,557
shares of common stock on a pro rata basis to the stockholders and warrant holders of GETI. GETI obtained effective control of Infinity Corp. subsequent to the Merger and thus the Merger was accounted as a reverse acquisition and recapitalization of GETI in accordance with ASC 805
- Business Combinations.
Subsequent to the Merger, the GETI shareholders retained a substantial majority of voting interest and positions on the Board of Directors. Additionally GETI's management is retained and GETI's operations comprise the ongoing operations post-Merger.
In the consolidated financial statements, the number of shares of common stock attributable to the Company is reflected retroactive to
January 1, 2014
to facilitate comparability to prior periods. Accordingly, the number of shares of common stock presented as outstanding as of
January 1, 2014
totals
22,450,688
which represents the number of post-Merger common shares that were received for pre-Merger GETI preferred stock, common stock and warrants outstanding as of
January 1, 2014
.
The following table (
in thousands, except share amounts
) presents the consolidated statements of temporary equity and stockholders' equity as if the Merger had occurred on
January 1, 2014
. The beginning balances as of
January 1, 2014
, shown in the table below, represent the Company's pre-Merger temporary equity and stockholders' equity previously stated as of
January 1, 2014
. The balances as of
January 1, 2014
, as converted, represent the post-Merger stockholders' equity received in exchange for the pre-Merger temporary equity and stockholders' equity at
January 1, 2014
.
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Temporary equity - convertible redeemable preferred stock
|
|
Stockholders' equity
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
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|
|
|
|
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|
|
|
|
Total
|
|
|
|
|
|
Additional
|
|
|
|
Total
|
|
|
Series A Preferred
|
|
Series B Preferred
|
|
Series C Preferred
|
|
Series C-1 Preferred
|
|
temporary
|
|
Common stock
|
|
paid-in
|
|
Accumulated
|
|
stockholders'
|
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
equity
|
|
Shares
|
|
Par value
|
|
capital
|
|
deficit
|
|
equity
|
|
Balances as of January 1, 2014
|
475,541
|
|
|
$
|
13,762
|
|
|
2,901,052
|
|
|
$
|
31,900
|
|
|
7,296,607
|
|
|
$
|
29,773
|
|
|
4,462,968
|
|
|
$
|
3,234
|
|
|
$
|
78,669
|
|
|
3,295,771
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
(76,379
|
)
|
|
$
|
(76,378
|
)
|
|
Reversal of pre-Merger temporary equity
|
(475,541
|
)
|
|
(13,762
|
)
|
|
(2,901,052
|
)
|
|
(31,900
|
)
|
|
(7,296,607
|
)
|
|
(29,773
|
)
|
|
(4,462,968
|
)
|
|
(3,234
|
)
|
|
$
|
(78,669
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
78,669
|
|
|
78,669
|
|
|
Reversal of pre-Merger common shares
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,295,771
|
)
|
|
(1
|
)
|
|
1
|
|
|
—
|
|
|
—
|
|
|
Reclassification of pre-Merger warrants from liability to additional paid-in capital
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13,905
|
|
|
—
|
|
|
13,905
|
|
|
Conversion of pre-Merger shares to post-Merger shares
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,450,688
|
|
|
2
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
Segregate historical accumulated deficit from additional paid-in capital
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47,705
|
|
|
(47,705
|
)
|
|
—
|
|
|
Balances as of January 1, 2014, as converted
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
22,450,688
|
|
|
$
|
2
|
|
|
$
|
61,609
|
|
|
$
|
(45,415
|
)
|
|
$
|
16,196
|
|
Not shown in the above table is the pre-Merger issuance by GETI of common shares, preferred shares and warrants. During 2013, there were
229,108
common shares issued which were exchanged for
79,003
shares of common stock in the Merger. On March 13, 2014, GETI issued
1,842,028
C-2 preferred shares and
1,640,924
C-2 preferred warrants. These shares and warrants were exchanged for
1,133,869
shares of common stock in the Merger.
The following table shows the number of common stock of the Company issued and outstanding related to the consummation of the Merger:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ordinary shares issued to Infinity Corp. founder shareholders
|
1,437,500
|
|
|
Ordinary shares issued to Infinity Corp. shareholders
|
5,750,000
|
|
|
Less: Ordinary shares redeemed
|
(2,351,533
|
)
|
|
Ordinary shares issued underwriter for UPO warrant conversion
|
100,000
|
|
|
Ordinary shares issued for PIPE Investment (excluding Petro-Hunt portion of the PIPE Investment)
|
812,500
|
|
|
Ordinary shares issued for PIPE Investment (Petro-Hunt portion of PIPE Investment)
|
250,000
|
|
|
Ordinary shares issued for the optional PIPE Investment
|
909,982
|
|
|
Ordinary shares issued to Glori Energy Inc. shareholders
|
23,584,557
|
|
|
|
|
|
|
|
30,493,006
|
|
In connection with the Merger, the Company received approximately
$24.7 million
, net of certain expenses and fees, and approximately
$13.7 million
in cash from the private placement of
1,722,482
shares of common stock at
$8.00
per share from Infinity Group, Hicks Equity Partners LLC and other investors. All of GETI’s previously outstanding common shares, preferred shares and warrants were exchanged for approximately
23,584,557
common shares in the newly merged entity, and accordingly, the Company no longer has liabilities for the fair value of such warrants and temporary equity previously reported in the Company's consolidated balance sheets. Additionally on April 14, 2014 Petro-Hunt L.L.C. ("Petro-Hunt") exercised its option to convert their
$2.0 million
receivable from the Company to common shares at
$8.00
per share or
250,000
shares (see
NOTE 10
).
In addition to the common stock issued in the Merger, the Company has
5,321,700
warrants outstanding at
December 31, 2014
and
December 31, 2015
to purchase common stock of the Company at a per share price of
$10
which expire on July 19, 2017.
NOTE 5
- PROPERTY AND EQUIPMENT
Property and equipment consists of the following (
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2014
|
|
2015
|
|
|
|
|
|
|
Proved oil and gas properties - successful efforts
|
$
|
45,694
|
|
|
$
|
48,454
|
|
|
Unproved oil and gas properties
|
196
|
|
|
443
|
|
|
Construction in progress
|
589
|
|
|
594
|
|
|
Laboratory and warehouse facility
|
640
|
|
|
648
|
|
|
Laboratory and field service equipment
|
3,158
|
|
|
3,355
|
|
|
Office equipment, computer equipment, vehicles and other
|
1,358
|
|
|
1,399
|
|
|
|
51,635
|
|
|
54,893
|
|
|
|
|
|
|
|
Less: accumulated depreciation, depletion and amortization (1)
|
(22,822
|
)
|
|
(47,578
|
)
|
|
Total property and equipment, net
|
$
|
28,813
|
|
|
$
|
7,315
|
|
(1) Includes impairment and excludes accretion of asset retirement obligation.
Depreciation, depletion and amortization consists of the following (
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
Depreciation and amortization expense
|
$
|
523
|
|
|
$
|
628
|
|
|
Depletion expense
|
3,960
|
|
|
4,723
|
|
|
Accretion of asset retirement obligation
|
141
|
|
|
156
|
|
|
Total depreciation, depletion, and amortization of property and equipment
|
$
|
4,624
|
|
|
$
|
5,507
|
|
On March 14, 2014, a subsidiary of the Company, GEP, acquired certain oil, gas and mineral leases in Wood County Texas (the “Coke Field”) from Petro-Hunt L.L.C. (“Petro-Hunt”) for (i)
$38.0 million
in cash and a
$2.0 million
convertible note payable (see
NOTE 10
) to Petro-Hunt, subject to certain purchase price adjustments primarily for net revenues in excess of direct operating expenses of the property from January 1, 2014 through the closing date, March 14, 2014, and (ii) the assumption of the asset retirement obligation related to plugging and abandoning the Coke Field Assets.
Of the total
$39.2 million
total purchase price of the Coke Field, the Company recognized, at approximate fair market value, assets such as office equipment and trucks included in property and equipment on the Company’s consolidated balance sheet of approximately
$310,000
and items such as tubular stock of
$327,000
classified in other property and equipment on the Company’s consolidated balance sheet. The remaining purchase price balance was allocated to proved oil and gas properties in property and equipment on the Company’s consolidated balance sheet. Also included in proved oil and gas properties, the Company recognized an asset associated with the asset retirement obligation (plugging and abandonment of wells) of
$745,000
and an offsetting liability included in other long-term liabilities on the Company’s consolidated balance sheet.
In September 2014, the Company purchased additional oil, gas and mineral leases adjacent to the Coke Field (the "Southwest Operating Field"). The Company purchased the Southwest Operating Field for
$2,000,000
and assumed an asset retirement obligation of an estimated
$138,000
.
The Company has included revenues and expenses related to the Coke Field for the period from March 14 through
December 31, 2014
in the consolidated statement of operations for the year ended
December 31, 2014
and for the acquisition of the Southwest Operating Field September 1 through December 31, 2014. For this period, the revenues and net loss attributable to the Coke Field and Southwest Operating Field were
$11,398,000
and
$7,061,000
, respectively. The net loss includes a
$6,023,000
gain on commodity derivatives related to the Company's volume based production swaps (see
NOTE 9
) and loss on impairment of oil and gas properties of
$12,707,000
.
The following summary presents unaudited pro forma information for the Company for the
year ended December 31, 2014
, as if the Coke Field acquisition had been consummated at January 1, 2014 (
in thousands, except per share amounts
):
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
|
|
|
Total revenues
|
$
|
18,604
|
|
|
Net loss
|
(19,111
|
)
|
|
|
|
|
Net loss per common shares, basic and diluted
|
$
|
(0.66
|
)
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
Basic
|
28,855
|
|
|
Diluted
|
28,855
|
|
On July 1, 2015 the Company sold its mineral interests in the "Etzold Field" located in Seward County, Kansas. The Etzold Field was originally purchased in 2010 as a greenfield lab to advance the development of the Company's AERO technology, and the operations have historically been included in the Company's Oil and Gas Segment (see
NOTE 16
). With the purchase of the larger Coke Field and with the Company's future acquisition plans, the Company made the strategic decision to divest the Etzold Field. Prior to the sale, the Company had associated net assets of
$89,000
, which were composed primarily of the purchase and development charges less accumulated depreciation and depletion and associated liabilities of
$435,000
related to the plugging and abandonment obligation associated with the Etzold Field. In exchange for the leasehold interest in the field, the Company received
$75,000
and the purchaser's assumption of the related asset retirement obligation. The Company recognized a gain on the sale of
$422,000
.
The following table is a summarized operational history of the Etzold Field
(in thousands)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
|
|
|
|
|
Revenue
|
$
|
327
|
|
|
$
|
57
|
|
|
Expenses
|
433
|
|
|
200
|
|
|
Net loss from operations
|
(106
|
)
|
|
(143
|
)
|
|
|
|
|
|
|
Income taxes
|
—
|
|
|
—
|
|
|
|
|
|
|
|
Net loss
|
$
|
(106
|
)
|
|
$
|
(143
|
)
|
On June 1, 2015, a subsidiary of the Company, GEP, executed a purchase and sale agreement to acquire certain proved oil and gas mineral leases in Refugio County, Texas (the “Bonnie View Field”) from a third party seller for
$2,644,000
. The carrying value of the Bonnie View Field is also increased by an asset retirement obligation associated with plugging and abandoning the Bonnie View Field of
$432,000
. The effective date of the purchase was May 1, 2015. The Company included revenues and expenses related to the Bonnie View Field from June 1, 2015 to December 31, 2015 on our consolidated income statement. For this period, the revenues and net loss attributable to the Bonnie View Field was
$447,000
and
$3,208,000
, respectively. The net loss includes a loss on impairment of oil and gas properties of
$2,400,000
. The Bonnie View Field does not meet the definition of a significant acquisition which would require pro forma financial information.
NOTE 6
– ASSET RETIREMENT OBLIGATION
The Company accounts for its asset retirement obligation (“ARO”) in accordance with ASC 410,
Asset Retirement and Environmental Obligations
. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site
reclamation, and similar activities associated with our oil and gas properties. The fair value of a liability for an ARO is required to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made and the associated retirement costs can be capitalized as part of the carrying amount of the long-lived asset. The Company determined its ARO by calculating the present value of the estimated cash flows related to the liability based upon estimates derived from management and external consultants familiar with the requirements of the retirement. The Company has not funded nor dedicated any assets to the retirement obligation.
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 plugging and abandonment costs.
The following is a reconciliation of the liability for the years ended
December 31, 2014
and
2015
(
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
Balance at the beginning of period
|
$
|
305
|
|
|
$
|
1,329
|
|
|
Liabilities acquired during the period
|
883
|
|
|
451
|
|
|
Liabilities settled during the period
|
—
|
|
|
(44
|
)
|
|
Accretion expense
|
141
|
|
|
156
|
|
|
Sold
|
—
|
|
|
(435
|
)
|
|
Revisions in estimates
|
—
|
|
|
65
|
|
|
Balance at the end of the period
|
$
|
1,329
|
|
|
$
|
1,522
|
|
The increase in liabilities acquired during the year ended
December 31, 2014
, was due to the acquisition of the Coke Field and the Southwest Operating Assets.
The increase in liabilities acquired during the year ended
December 31, 2015
, was due to the acquisition of the Bonnie View Field and drilling activity at the Coke Field. The decreases due to sold wells were due to the sale of the Etzold Field. Additionally, estimated plug date revisions and well plugging and abandonment during the year ended
December 31, 2015
caused the changes in the revisions in estimates and liabilities settled during the period, respectively.
The asset retirement obligation is included in the consolidated balance sheets as follows
(in thousands)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2014
|
|
2015
|
|
Accrued liabilities
|
$
|
—
|
|
|
$
|
65
|
|
|
Asset retirement obligation
|
1,329
|
|
|
1,457
|
|
|
|
$
|
1,329
|
|
|
$
|
1,522
|
|
NOTE 7
– ACCRUED EXPENSES
As of
December 31, 2014
and
2015
, the significant components of accrued expenses reported in the accompanying consolidated balance sheets are as follows (
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2014
|
|
2015
|
|
Accrued compensation and benefits
|
$
|
892
|
|
|
$
|
91
|
|
|
Accrued end-of-term charge (see NOTE 10)
|
240
|
|
|
—
|
|
|
Accrued interest
|
15
|
|
|
386
|
|
|
Accrued taxes
|
223
|
|
|
47
|
|
|
Accrued royalties
|
164
|
|
|
134
|
|
|
Asset retirement obligations
|
—
|
|
|
65
|
|
|
Accrued lease operating expenses and other
|
258
|
|
|
457
|
|
|
|
$
|
1,792
|
|
|
$
|
1,180
|
|
NOTE 8
– FAIR VALUE MEASUREMENTS
The following table summarizes the financial assets measured at fair value, on a recurring basis as of
December 31, 2014
and
2015
(
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
December 31, 2014
|
|
|
|
|
|
|
|
|
Short-term commodity derivatives, asset
|
$
|
—
|
|
|
$
|
2,905
|
|
|
$
|
—
|
|
|
$
|
2,905
|
|
|
Long-term commodity derivatives, asset
|
—
|
|
|
2,891
|
|
|
—
|
|
|
2,891
|
|
|
|
$
|
—
|
|
|
$
|
5,796
|
|
|
$
|
—
|
|
|
$
|
5,796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements using
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
Short-term commodity derivatives, asset
|
$
|
—
|
|
|
$
|
3,411
|
|
|
$
|
—
|
|
|
$
|
3,411
|
|
The Level 2 instruments presented in the table above consists of derivative instruments made up of commodity price swaps. The fair values of the Company's commodity derivative instruments are based upon the NYMEX futures value of oil less the contracted per barrel rate to be received. The Company records a liability associated with the futures contracts when the futures price of oil is greater than the contracted per barrel rate to be received and an asset when the futures price of oil is less than the contracted per barrel rate to be received.
NOTE 9
- DERIVATIVE INSTRUMENTS
The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. The Company is currently engaged in oil commodity price swaps where a fixed price is received for a portion of the Company's oil production. In return, the Company pays a floating price based upon NYMEX oil prices. Although these arrangements are designed to reduce the downside risk of a decline in oil prices on the covered production, they conversely limit potential income from increases in oil prices and expose the Company to the credit risk of counterparties. The Company manages the default risk of counterparties by engaging in these agreements with only high credit quality multinational energy companies and through the continuous monitoring of their performance.
As of
December 31, 2015
the Company had the following open positions on its outstanding commodity derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Volume/Month (Bbls)
|
|
Price/Unit
|
|
Fair Value - Asset
|
|
January 2016 - March 2016
|
|
7,300
|
|
|
$
|
86.50
|
|
|
$
|
1,053,000
|
|
|
April 2016 - December 2016
|
|
6,550
|
|
|
$
|
82.46
|
|
|
$
|
2,358,000
|
|
The derivative contracts are carried at fair value on the consolidated balance sheet as assets or liabilities. The Company has not elected to designate any of these as derivative contracts for hedge accounting. Accordingly, for each reporting period the contracts are marked-to-market and the resulting unrealized changes in the fair value of the assets and liabilities are recognized on the consolidated statements of operations. The payables and receivables resulting from the closed derivative contracts result in realized gains and losses recorded on the Company's consolidated statements of operations. The unrealized and realized gains and losses on derivative instruments are recognized in the gain on commodity derivatives line item located in other (expense) income.
The Company settled its long-term commodity derivative assets on December 23, 2015 in exchange for
$2,725,000
. At the time of the sale the NYMEX value for the sold portion of the commodity swaps was
$3,192,000
. Accordingly the sale resulted in a
$467,000
loss on commodity derivatives which is included in the gain on commodity derivatives line item on the Company's consolidated statements of operations. As of
December 31, 2014
and
2015
the Company had a current asset for commodity derivatives of
$2,905,000
and
$3,411,000
.
The following tables summarize the unrealized and realized gain on commodity derivatives
(
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
Unrealized gain on commodity derivatives
|
$
|
5,796
|
|
|
$
|
340
|
|
|
Early termination of long-term commodity derivatives
|
—
|
|
|
(2,725
|
)
|
|
Realized gain on commodity derivatives
|
227
|
|
|
6,346
|
|
|
|
$
|
6,023
|
|
|
$
|
3,961
|
|
NOTE 10
- LONG TERM DEBT
On June 11, 2012, the Company entered into a secured term promissory note in the amount of
$8.0 million
. The note contained a
10.0%
annual interest rate subject to increase based upon an increase in the prime rate. The loan is secured by substantially all assets of the Company, with the exception of the Coke Field Assets. The lender also received a warrant to purchase shares of the Company’s stock, which were exchanged for
18,208
common shares upon consummation of the Merger. Equal monthly principal payments were due over
27 months
beginning in April 2013 through June 2015, plus an end of term charge of
$280,000
. As of
December 31, 2014
, the ratable liability for the end of term charge was
$240,000
and it is included in other long-term liabilities and accrued expenses in current liabilities on the accompanying
2014
consolidated balance sheet. The loan agreement contains covenants which place restrictions on the incurrence of debt, liens and capital expenditures. As of
December 31, 2014
the outstanding loan balance was
$1,750,000
. On
March 2, 2015
the Company elected to prepay the entire remaining indebtedness. The payment included remaining principal of
$888,888
and the end of term charge of
$280,000
.
On March 14, 2014 in connection with the closing of the acquisition of the Coke Field Assets, the Company entered into
two
financing agreements of
$18.0 million
and
$4.0 million
in order to fund a portion of the
$38.0 million
in cash required for the acquisition.
The
$18.0 million
note is a senior secured term loan facility of GEP and is secured by the Coke Field and Bonnie View and shares of common stock of GEP. Glori Energy Inc does not guarantee the debt of GEP. The loan has a
three
year term bearing interest at
11.0%
per annum, subject to increase upon a LIBOR rate increase above
1%
. The credit agreement requires quarterly principal payments equal to
50%
of the excess cash flows, as defined, from the Coke Field Assets during the first year and
75%
thereafter subject to a minimum quarterly principal payment of
$112,500
plus interest.
The loan was funded net of closing costs of
2%
, or
$360,000
, which is included in deferred loan costs on the consolidated balance sheets and is being amortized over the loan term. The loan agreement contains covenants which place restrictions on GEP’s ability to incur additional debt, incur other liens, make other investments, capital expenditures and the sale of assets.
Commencing with the quarter ended
June 30, 2014
, GEP is also required to maintain certain financial ratios related to debt, working capital and proved reserves, all as defined in the loan agreement. In May and November of each year, in accordance with a procedure outlined in the loan agreement, the value of the collateral securing the note is redetermined based on engineering reserve reports submitted by GEP. As of
December 31, 2014
and
December 31, 2015
, the outstanding loan balance was
$17,428,000
and
$10,452,000
, respectively. GEP is in compliance with all covenants as of
December 31, 2015
. On March 18, 2016, GEP entered into an amendment to the credit agreement on the senior secured term loan facility with its lender, Stellus Capital Investment Corporation, which had the effect of removing the financial ratio covenants and the semi-annual collateral value redetermination until maturity in March 2017. In connection with the amendment, the interest rate on the loan increased to
13.0%
per annum from
11.0%
, with the additional
2.0%
increase to be “paid in kind”, or added to the principal amount. In addition, principal of
$37,500
plus interest is payable monthly compared to the minimum principal payments of
$112,500
plus interest which was previously payable quarterly. Without this amendment we likely would not have been able to meet all of our financial covenants in the future.
The
$4.0 million
note had a
two
year term bearing interest at
12.0%
per annum and is secured by the assets of the Company but was subordinated to existing Company debt. The loan was funded net of closing costs of
2%
, or
$80,000
, which were initially included in deferred loan costs on the consolidated balance sheet. The
$4.0 million
note principal and a
$400,000
prepayment penalty plus accrued interest was paid in full on May 13, 2014, and the related remaining deferred loan costs were expensed.
On March 14, 2014, in connection with the purchase of the Coke Field Assets, a subsidiary of the Company, GEP, issued to Petro-Hunt an unsecured, subordinated convertible promissory note for
$2.0 million
bearing interest at
6.0%
per annum. On April 14, 2014 the note was converted into
250,000
shares of post-Merger common stock.
Maturities on long-term debt during the next five years are as follows (
in thousands
):
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
Amount
|
|
|
|
|
|
2016
|
|
$
|
480
|
|
|
2017
|
|
10,012
|
|
|
2018
|
|
9
|
|
|
2019
|
|
9
|
|
|
2020
|
|
9
|
|
|
Thereafter
|
|
6
|
|
|
|
|
$
|
10,525
|
|
NOTE 11
- LOSS PER SHARE
The Company follows current guidance for share-based payments which are considered as participating securities. Share-based payment awards that contain non-forfeitable rights to dividends, whether paid or unpaid, are designated as participating securities and are included in the computation of basic earnings per share. However, in periods of net loss, participating securities other than common stock are not included in the calculation of basic loss per share because there is not a contractual obligation for owners of these securities to share in the Company’s losses, and the effect of their inclusion would be anti-dilutive.
The following table sets forth the computation of basic and diluted earnings per share (
in thousands, except per share data
):
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
|
|
|
Numerator:
|
|
|
|
|
Net loss
|
$
|
(18,756
|
)
|
|
$
|
(36,255
|
)
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
Weighted-average common shares outstanding - basic
|
28,855
|
|
|
31,769
|
|
|
Effect of dilutive securities
|
—
|
|
|
—
|
|
|
Weighted-average common shares - diluted
|
28,855
|
|
|
31,769
|
|
|
|
|
|
|
|
Net loss per common share - basic and diluted
|
$
|
(0.65
|
)
|
|
$
|
(1.14
|
)
|
The following weighted average securities outstanding during the periods below were not included in the calculation of diluted shares outstanding as they would have been anti-dilutive (
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
Common stock warrants ($10 strike price)
|
4,895
|
|
|
5,321
|
|
|
Common stock options
|
2,311
|
|
|
2,039
|
|
|
Restricted shares
|
—
|
|
|
82
|
|
NOTE 12
- INCOME TAXES
At
December 31, 2014
and
2015
, the Company had operating loss carryforwards for federal income tax reporting purposes of approximately
$45.7 million
and
$64.5 million
, respectively, which will begin to expire in the year 2025, net operating losses for state income tax reporting purposes of approximately
$6.6 million
and
$6.7 million
, respectively, which will begin to expire in 2021, and tax credits of approximately
$508,000
which will begin to expire in 2027. The Net Operating Loss ("NOL") carry forward has been reduced by approximately
$5.4 million
because management estimates such amount of the loss carry forwards will expire due to limitations from changes in control.
Income tax benefit for the periods presented differs from the U.S. Federal benefit calculated at the statutory income tax rate due to the following (
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
|
|
|
Federal benefit at statutory income tax rate
|
$
|
(6,692
|
)
|
|
$
|
(12,374
|
)
|
|
R&D credits
|
(83
|
)
|
|
(58
|
)
|
|
Non-deductible (taxable) expenses & other items
|
(380
|
)
|
|
422
|
|
|
State income taxes - net of federal benefit
|
(221
|
)
|
|
(33
|
)
|
|
Foreign income taxes
|
209
|
|
|
(182
|
)
|
|
Change in valuation allowance
|
7,376
|
|
|
12,043
|
|
|
Taxes on income
|
$
|
209
|
|
|
$
|
(182
|
)
|
The tax effects of temporary differences that give rise to significant portions of the Company’s net deferred tax assets at
December 31, 2014
and
2015
are as follows (
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
|
|
|
|
|
Current deferred tax asset
|
|
|
|
|
|
|
Deferred revenue and other
|
$
|
248
|
|
|
$
|
9
|
|
|
Less valuation allowance
|
(225
|
)
|
|
(9
|
)
|
|
|
23
|
|
|
—
|
|
|
|
|
|
|
|
Current deferred tax liability
|
|
|
|
|
|
|
Current portion of swap asset
|
993
|
|
|
1,161
|
|
|
|
|
|
|
|
Current deferred tax liability, net
|
970
|
|
|
1,161
|
|
|
|
|
|
|
|
Non-current deferred tax asset
|
|
|
|
|
|
|
NOL carryforwards (long-term)
|
16,077
|
|
|
22,233
|
|
|
R&D credits
|
450
|
|
|
508
|
|
|
Stock compensation
|
154
|
|
|
346
|
|
|
Depreciable property basis
|
740
|
|
|
450
|
|
|
Oil and gas properties
|
4,040
|
|
|
9,386
|
|
|
|
21,461
|
|
|
32,923
|
|
|
Less valuation allowance
|
(19,503
|
)
|
|
(31,762
|
)
|
|
|
1,958
|
|
|
1,161
|
|
|
|
|
|
|
|
Non-current deferred tax liability
|
|
|
|
|
|
|
Non-current portion of swap asset
|
988
|
|
|
—
|
|
|
Non-current deferred tax asset, net
|
970
|
|
|
1,161
|
|
|
|
|
|
|
|
Total deferreds, net
|
$
|
—
|
|
|
$
|
—
|
|
The provision (benefit) for income taxes from continuing operations for the periods indicated are comprised of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
|
|
|
Current tax provision (benefit):
|
|
|
|
|
Federal
|
—
|
|
|
—
|
|
|
Foreign
|
209
|
|
|
(182
|
)
|
|
State
|
—
|
|
|
—
|
|
|
Total
|
$
|
209
|
|
|
$
|
(182
|
)
|
|
|
|
|
|
|
Deferred tax provision (benefit):
|
|
|
|
|
Federal
|
—
|
|
|
—
|
|
|
Foreign
|
—
|
|
|
—
|
|
|
State
|
—
|
|
|
—
|
|
|
Total
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
Total tax provision (benefit):
|
|
|
|
|
Federal
|
—
|
|
|
—
|
|
|
Foreign
|
209
|
|
|
(182
|
)
|
|
State
|
—
|
|
|
—
|
|
|
Total
|
$
|
209
|
|
|
$
|
(182
|
)
|
The valuation allowance for deferred tax assets increased by
$12.0 million
in 2015. In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As we have incurred net operating losses in 2015 and prior years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. Therefore, with the before-mentioned adjustment of
$12.0 million
, we have reduced the carrying value of our net deferred tax asset to
zero
. The valuation allowance has no impact on our net operating loss position for tax purposes, and if we generate taxable income in future periods, we will be able to use our NOLs to offset taxes due at that time. We will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.
Internal Revenue Code Section 382 places a limitation (the “Section 382 Limitation”) on the amount of taxable income that can be offset by an NOL after a change in control (typically, a greater than 50% change in ownership) of a loss corporation. Generally, after a control change, loss corporations cannot deduct NOL carryforwards in excess of the Section 382 Limitation.
As of December 31, 2013, the Company had an uncertain tax position related to not filing Form 926 Return by a U.S. Transferor of Property to a Foreign Corporation in the amount of approximately
$31,000
, for the tax years 2010 and 2011 and these forms would have reported cash transfers to support the operations of its subsidiary Glori Oil S.R.L. The Company has amended these returns and believes any liability will be abated and no longer has an uncertain tax position; accordingly, the Company has not recognized any liability in the accompanying consolidated financial statements. The Company does not expect a material change to the consolidated financial statements related to uncertain tax positions in the next 12 months. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense.
Management believes that the issuance of Series B Preferred Stock on October 15, 2009 has resulted in the Section 382 Limitation, and thereby the federal net operating loss carryovers have been reduced by the estimated effect.
The Company's
$22.2 million
deferred tax asset related to the NOL carryforwards is net of
$87,000
of unrealized excess tax benefits related to stock based compensation. The impact of the excess tax benefit will be recognized in additional paid-in capital upon utilization of the Company's NOL and tax credit carryforwards.
NOTE 13
– EMPLOYEE RETIREMENT SAVINGS PLAN
The Company sponsors an employee retirement saving plan (the “401(k) Plan”) that is intended to qualify under Section 401(k) of the Internal Revenue Code. The 401(k) Plan is designed to provide eligible employees with an opportunity to make regular voluntary contributions into a long-term investment and saving program. There is no minimum age or service requirement to participate, and the Company may make discretionary matching contributions. For the years ended
December 31, 2014
and
2015
the Company made matching contributions of
$67,000
and
$71,000
, respectively.
NOTE 14
- COMMITMENTS AND CONTINGENCIES
Litigation
From time to time, the Company may be subject to legal proceedings and claims that arise in the ordinary course of business. The Company is not a party to any material litigation or proceedings and is not aware of any material litigation or proceedings, pending or threatened against it.
Commitments
The Company leases
two
buildings in Houston, Texas and a warehouse facility in Gull Lake, Saskatchewan under operating leases. The Company entered into a
two
-year lease agreement in October of 2014 for
7,805
square feet of office space in Houston's Westchase District for
$18,000
per month, with a
one
-year extension option at a
4%
increase in rent and
two
one
-year extension options at a to be mutually agreed upon market rate with the lessor. The Company does not intend to renew this lease upon expiration in 2016. The Company's original Houston building lease, which contains office space, warehouse space and a laboratory, expires in May 2017 and is leased for
$11,000
per month. The Saskatchewan warehouse is a month-to-month lease which rents for
$1,000
per month CDN and is cancelable with
30 days
’ notice.
Approximate minimum future rental payments under these noncancelable operating leases as of
December 31, 2015
are as follows (
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
|
|
2016
|
|
$
|
295
|
|
|
2017
|
|
53
|
|
|
|
|
$
|
348
|
|
Total rent expense for the
years ended December 31,
2014
, and
2015
, was
$291,000
and
$340,000
, respectively.
NOTE 15
- STOCK-BASED COMPENSATION
Stock Incentive Plan
As a result of the Merger with Infinity Corp. which consummated on
April 14, 2014
, the issued and outstanding stock options were canceled and reissued as stock options in the newly merged entity at a conversion ratio of
2.9
to
1.0
pre-Merger stock options to post-Merger stock options. The exercise price of the Glori stock options also increased by the same factor of
2.9
. All pre-Merger option disclosures in the note below are shown as converted using these factors. As of
December 31, 2014
, the total common stock available for issuance pursuant to the Glori Oil Limited 2006 Stock Option and Grant Plan (the “Plan”) was
2,581,190
, as converted. As of
April 14, 2014
, the plan was amended such that no further options would be issued.
In
December 2014
, the Company approved the adoption of the 2014 Long Term Incentive Plan ("the 2014 Plan") which authorized
2,000,000
shares to be available for issuance to officers, directors, employees, and affiliates of the Company. Options are issued at an exercise price equal to the fair market value of the Company’s common stock at the grant date. Generally, the options vest
25 percent
after
one year
, and thereafter ratably by month over the following
36 months
, and may be exercised for a period of
10 years
subject to vesting. As of
December 31, 2015
, the total common stock available for issuance pursuant to the 2014 Plan was
40,667
.
Stock-based compensation expense is included primarily in selling, general and administrative expense and was
$296,000
and
$1,412,000
for the
years ended December 31,
2014
, and
2015
, respectively.
The Company has future unrecognized compensation expense for nonvested shares at
December 31, 2015
of
$2,228,000
which have a weighted average vesting period of
2.8 years
.
Stock Option Awards:
The following table summarizes the activity of the Company’s plan related to stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of options
|
|
Weighted
average
exercise
price per share
|
|
Weighted
average
remaining
contractual
term (years)
|
|
Aggregate intrinsic value
|
|
Outstanding as of January 1, 2014
|
2,322,180
|
|
|
0.81
|
|
|
7.7
|
|
782,000
|
|
|
Awarded
|
7,103
|
|
|
1.16
|
|
|
|
|
|
|
Exercised
|
(9,397
|
)
|
|
1.16
|
|
|
|
|
70,000
|
|
|
Forfeited or Expired (1)
|
(19,836
|
)
|
|
1.16
|
|
|
|
|
|
|
Outstanding as of December 31, 2014
|
2,300,050
|
|
|
0.82
|
|
|
6.7
|
|
7,725,000
|
|
|
Awarded
|
924,234
|
|
|
1.54
|
|
|
|
|
|
|
Exercised
|
(211,246
|
)
|
|
0.66
|
|
|
|
|
456,000
|
|
|
Forfeited or Expired (1)
|
(178,403
|
)
|
|
1.80
|
|
|
|
|
|
|
Outstanding as of December 31, 2015
|
2,834,635
|
|
|
1.01
|
|
|
6.9
|
|
89,000
|
|
|
Exercisable as of December 31, 2015
|
1,934,605
|
|
|
0.84
|
|
|
5.7
|
|
89,000
|
|
|
|
|
|
(1)
|
Management considers the circumstances generating these forfeitures to be unusual and nonrecurring in nature; accordingly, no allowance for forfeitures of options to purchase shares has been considered in determining future vesting or expense.
|
The weighted-average grant date fair value for option awards granted during the year was
$0.66
and
$0.96
for the
year ended December 31, 2014
and
2015
, respectively. The total fair value of equity awards vested during the
year ended December 31, 2014
and
2015
was
$303,000
, and
$249,000
, respectively.
The Company has computed the fair value of all options granted during the years ended
December 31, 2014
and
2015
using the Black-Scholes option pricing model using the following assumptions:
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
|
|
|
|
|
Risk-free interest rate
|
2.44%
|
|
1.55%
|
|
Expected volatility
|
55%
|
|
66%
|
|
Expected dividend yield
|
—
|
|
—
|
|
Expected life (in years)
|
7.00
|
|
6.00
|
|
Expected forfeiture rate
|
—
|
|
—
|
Restricted Share Awards:
In addition to options during the
year ended December 31, 2015
the Company granted restricted share awards to certain executives and members of the board of directors. The following table shows a summary of restricted stock activity for the
year ended December 31, 2015
:
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted-average grant date fair value
|
|
Non-vested awards outstanding, December 31, 2014
|
—
|
|
|
—
|
|
|
Granted
|
1,040,540
|
|
|
$
|
2.65
|
|
|
Vested
|
(150,808
|
)
|
|
2.65
|
|
|
Forfeited
|
(45,140
|
)
|
|
2.13
|
|
|
Non-vested awards outstanding, December 31, 2015
|
844,592
|
|
|
$
|
2.67
|
|
NOTE 16
– SEGMENT INFORMATION
The Company generates revenues through the production and sale of oil and natural gas (the “Oil and Gas Segment”) and through the Company’s services provided to third party oil companies (the “AERO Services Segment”). The Oil and Gas Segment produces and develops the Company’s acquired oil and natural gas interests and the revenues derived from this segment are from sales to the first purchaser. During 2015, the Company used
three
such arrangements for oil sales,
one
for the Etzold Field located in Seward County, Kansas and
one
for oil for the Coke Field located in Wood County, Texas and
one
for the Bonnie View Field located in Refugio County, Texas.
The AERO Services Segment derives revenues from external customers by providing the Company’s biotechnology solutions of enhanced oil recovery through a
two
-step process consisting of (1) the Analysis Phase and (2) the Field Deployment Phase.
The Analysis Phase work is a reservoir screening process whereby the Company obtains field samples and evaluates the Company’s potential for AERO Services Segment success. This process is performed at the Company’s Houston laboratory facility. The Science and Technology expenses shown on the Company’s consolidated statements of operations are the expenses that are directly attributable to the Analysis Phase and expenses associated with the Company’s on-going research and development of its technology and are included in the "Corporate Segment".
In the Field Deployment Phase, the Company deploys skid mounted injection equipment used to inject nutrient solution in the oil reservoir. The work in this phase is performed in oil fields of customers located in the United States and internationally and in the Company’s own oil fields. The service operations expense shown on the Company’s consolidated statements of operations are the expenses that are directly attributable to the Field Deployment Phase and are included in the AERO Services Segment.
Earnings of industry segments exclude income taxes, interest income, interest expense and unallocated corporate expenses.
Although the AERO Services Segment provides enhanced oil recovery services to the Oil and Gas Segment, the Company does not utilize intercompany charges for these services. The direct costs of the services such as the injection solution, transportation of the solution and expenses associated with the injection are charged directly to the Oil and Gas Segment. All of the AERO Services Segment capital expenditures and depreciation associated with injection equipment is viewed as part of the AERO Services Segment.
The following tables set forth summary financial data by operating segments (
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas
|
|
AERO Services
|
|
Corporate
|
|
Total
|
|
Year ended December 31, 2014
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
11,724
|
|
|
$
|
4,135
|
|
|
$
|
—
|
|
|
$
|
15,859
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
10,777
|
|
|
3,528
|
|
|
7,788
|
|
|
22,093
|
|
|
Impairment of oil and gas properties
|
13,160
|
|
|
—
|
|
|
—
|
|
|
13,160
|
|
|
Depreciation, depletion and amortization
|
4,188
|
|
|
404
|
|
|
32
|
|
|
4,624
|
|
|
(Loss) income from operations
|
(16,401
|
)
|
|
203
|
|
|
(7,820
|
)
|
|
(24,018
|
)
|
|
|
|
|
|
|
|
|
|
|
Other income (expense)
|
6,023
|
|
|
—
|
|
|
(552
|
)
|
|
5,471
|
|
|
|
|
|
|
|
|
|
|
|
Taxes on income
|
—
|
|
|
—
|
|
|
209
|
|
|
209
|
|
|
Net (loss) income
|
(10,378
|
)
|
|
203
|
|
|
(8,581
|
)
|
|
(18,756
|
)
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
$
|
27,078
|
|
|
$
|
1,636
|
|
|
$
|
99
|
|
|
$
|
28,813
|
|
|
Total assets
|
$
|
34,163
|
|
|
$
|
1,789
|
|
|
$
|
31,483
|
|
|
$
|
67,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas
|
|
AERO Services
|
|
Corporate
|
|
Total
|
|
Year ended December 31, 2015
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
7,397
|
|
|
$
|
1,605
|
|
|
$
|
—
|
|
|
$
|
9,002
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
9,974
|
|
|
1,771
|
|
|
7,824
|
|
|
19,569
|
|
|
Impairment of oil and gas property
|
22,600
|
|
|
—
|
|
|
—
|
|
|
22,600
|
|
|
Depreciation, depletion and amortization
|
4,953
|
|
|
327
|
|
|
227
|
|
|
5,507
|
|
|
Loss from operations
|
(30,130
|
)
|
|
(493
|
)
|
|
(8,051
|
)
|
|
(38,674
|
)
|
|
|
|
|
|
|
|
|
|
|
Other income (expense)
|
4,382
|
|
|
—
|
|
|
(2,145
|
)
|
|
2,237
|
|
|
|
|
|
|
|
|
|
|
|
Taxes on income
|
—
|
|
|
—
|
|
|
(182
|
)
|
|
(182
|
)
|
|
Net loss
|
$
|
(25,748
|
)
|
|
$
|
(493
|
)
|
|
$
|
(10,014
|
)
|
|
$
|
(36,255
|
)
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
$
|
5,741
|
|
|
$
|
1,294
|
|
|
$
|
280
|
|
|
$
|
7,315
|
|
|
Total assets
|
$
|
10,098
|
|
|
$
|
1,816
|
|
|
$
|
10,350
|
|
|
$
|
22,264
|
|
The following table shows the total revenue by geography (
in thousands
):
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2014
|
|
2015
|
|
Revenues
|
|
|
|
|
United States
|
$
|
13,233
|
|
|
$
|
7,640
|
|
|
Canada
|
2,220
|
|
|
317
|
|
|
Brazil
|
406
|
|
|
1,045
|
|
|
Total revenues
|
$
|
15,859
|
|
|
$
|
9,002
|
|
NOTE 17
– SUPPLEMENTAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (Unaudited)
Reserve Quantity Information
For all years presented, the estimate of proved reserves and related valuations were based on reports prepared by the Company’s independent petroleum engineers.
Proved reserve estimates included herein conform to the definitions prescribed by the U.S. Securities and Exchange Commission. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions existing as of the end of each respective year. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods.
Presented below is a summary of the changes in estimated proved reserves of the Company, all of which are located in the United States, for the years ended
December 31, 2014
and
2015
:
Quantities of Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
|
|
Natural Gas
|
|
|
(Mbbls)
|
|
(Mmcf)
|
|
|
|
|
|
|
Proved Developed Reserves, January 1, 2014
|
18
|
|
|
—
|
|
|
Purchase of minerals in place (1)
|
1,728
|
|
|
384
|
|
|
Production
|
(133
|
)
|
|
(72
|
)
|
|
Revisions of previous estimates (2)
|
(211
|
)
|
|
(258
|
)
|
|
Proved Developed Reserves, December 31, 2014
|
1,402
|
|
|
54
|
|
|
Purchase of minerals in place (3)
|
74
|
|
|
68
|
|
|
Sale of minerals in place (4)
|
(14
|
)
|
|
—
|
|
|
Production
|
(155
|
)
|
|
(90
|
)
|
|
Revisions of Previous Estimates (5)
|
(612
|
)
|
|
19
|
|
|
Proved Developed Reserves, December 31, 2015
|
695
|
|
|
51
|
|
|
|
|
|
(1)
|
Purchase of the Coke Field Assets on March 14, 2014 and the Southwest Operating Assets on September 1, 2014.
|
|
|
|
|
(2)
|
The reserves revision is due to an increase in costs over our prior year reserve report.
|
|
|
|
|
(3)
|
Purchase of the Bonnie View Field on June 1, 2015.
|
|
|
|
|
(4)
|
Sale of the Etzold Field on July 1, 2015,
|
|
|
|
|
(5)
|
The oil reserves revision is due to a decline in oil prices throughout 2015.
|
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
|
|
Crude oil and condensate
|
|
Natural gas
|
|
|
(Mbbls)
|
|
(Mmcf)
|
|
|
|
|
|
|
December 31, 2014
|
|
|
|
|
|
Proved developed reserves
|
1,402
|
|
|
54
|
|
|
Proved undeveloped reserves
|
—
|
|
|
—
|
|
|
Total
|
1,402
|
|
|
54
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
|
|
Proved developed reserves
|
695
|
|
|
51
|
|
|
Proved undeveloped reserves
|
—
|
|
|
—
|
|
|
Total
|
695
|
|
|
51
|
|
Capitalized Costs Related to Oil and Gas Producing Activities
The following table presents the Company’s capitalized costs related to oil and gas producing activities at
December 31, 2014
and
2015
(in thousands)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2014
|
|
2015
|
|
|
|
|
|
|
Unproved properties
|
$
|
196
|
|
|
$
|
443
|
|
|
Proved properties
|
45,694
|
|
|
48,454
|
|
|
Total
|
45,890
|
|
|
48,897
|
|
|
Less - accumulated depreciation, depletion and amortization (1)
|
(19,612
|
)
|
|
(44,181
|
)
|
|
Net capitalized costs
|
$
|
26,278
|
|
|
$
|
4,716
|
|
|
|
|
|
(1)
|
Accumulated depreciation, depletion and amortization includes the
2014
oil and gas property impairment of
$13,160,000
and the
2015
impairment of
$22,600,000
.
|
Costs Incurred in Oil and Gas Producing Activities
The following table presents the net costs incurred in property acquisition, exploration and development activities for the years ended
December 31, 2014
and
2015
(in thousands)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
Acquisition of properties
|
$
|
42,788
|
|
|
$
|
3,705
|
|
|
Development
|
—
|
|
|
2,534
|
|
|
Total costs incurred
|
$
|
42,788
|
|
|
$
|
6,239
|
|
Results of Operations from Oil and Gas Producing Activities
The following table presents the Company’s results of operations from oil and gas producing activities for the years ended
December 31, 2013
,
2014
and
2015
(in thousands)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year ended December 31,
|
|
|
2014
|
|
2015
|
|
|
|
|
|
|
Revenues from oil and gas producing activities
|
$
|
11,724
|
|
|
$
|
7,397
|
|
|
|
|
|
|
|
Production costs
|
6,631
|
|
|
6,588
|
|
|
Exploration expense
|
—
|
|
|
102
|
|
|
Ad valorem taxes
|
438
|
|
|
420
|
|
|
State severance taxes
|
547
|
|
|
343
|
|
|
Impairment of oil and gas property
|
13,160
|
|
|
22,600
|
|
|
Depreciation, depletion and amortization
|
3,960
|
|
|
4,723
|
|
|
Total expenses
|
24,736
|
|
|
34,776
|
|
|
|
|
|
|
|
Pre-tax loss from producing activities
|
(13,012
|
)
|
|
(27,379
|
)
|
|
|
|
|
|
|
Income tax expense
|
—
|
|
|
—
|
|
|
Results of oil and gas producing activities
|
$
|
(13,012
|
)
|
|
$
|
(27,379
|
)
|
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with ASC 932,
Extractive Activities – Oil and Gas
. Future cash inflows as of
December 31, 2014
and
2015
, were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month periods ended
December 31, 2014
and
2015
) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming the continuation of existing economic conditions.
Future income tax expense is calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of the properties involved. Future income tax expense gives effect to permanent differences, tax credits and loss carry forwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of
10%
annually to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily result in an estimate of the fair value of the Company’s oil and gas properties.
Presented below is the standardized measure of discounted future net cash flows
(in thousands)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
Future cash inflows
|
$
|
133,235
|
|
|
$
|
33,926
|
|
|
Future production and development costs
|
|
|
|
|
|
|
Production
|
(86,032
|
)
|
|
(26,442
|
)
|
|
Development
|
—
|
|
|
(136
|
)
|
|
Future cash flows before income taxes
|
47,203
|
|
|
7,348
|
|
|
Future income taxes
|
—
|
|
|
—
|
|
|
Future net cash flows after income taxes
|
47,203
|
|
|
7,348
|
|
|
10% annual discount for estimated timing of cash flows
|
(17,111
|
)
|
|
(2,586
|
)
|
|
Standardized measure of discounted future net cash flows
|
$
|
30,092
|
|
|
$
|
4,762
|
|
The following reconciles the changes in the standardized measure of discounted future net cash flows
(in thousands)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2014
|
|
2015
|
|
|
|
|
|
|
Balance, beginning of year
|
$
|
561
|
|
|
$
|
30,092
|
|
|
Changes from:
|
|
|
|
|
|
Sales, net of production costs
|
(4,108
|
)
|
|
(46
|
)
|
|
Net changes in prices and production costs
|
2,445
|
|
|
(12,882
|
)
|
|
Extensions
|
—
|
|
|
544
|
|
|
Divestiture of reserves
|
—
|
|
|
(337
|
)
|
|
Revisions to quantity estimates
|
(8,044
|
)
|
|
(16,436
|
)
|
|
Accretion of discount
|
56
|
|
|
3,009
|
|
|
Purchases of reserves in place
|
38,211
|
|
|
1,188
|
|
|
Net changes in income taxes
|
—
|
|
|
—
|
|
|
Changes in timing of cash flows and other
|
971
|
|
|
(370
|
)
|
|
Balance, end of year
|
$
|
30,092
|
|
|
$
|
4,762
|
|
NOTE 18
- SELECTED QUARTERLY FINANCIAL RESULTS (Unaudited)
Unaudited quarterly operating results were as follows (
in thousands; except per share data
):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 (Quarter ended)
|
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
|
(Unaudited)
|
|
Net revenues
|
$
|
1,002
|
|
|
$
|
5,556
|
|
|
$
|
5,458
|
|
|
$
|
3,843
|
|
|
Loss from operations
|
(2,796
|
)
|
|
(1,880
|
)
|
|
(1,633
|
)
|
|
(17,709
|
)
|
|
Net loss applicable to stockholders
|
(684
|
)
|
|
(6,060
|
)
|
|
(356
|
)
|
|
(11,656
|
)
|
|
Net loss per common share, basic and diluted (1)
|
$
|
(0.60
|
)
|
|
$
|
(0.20
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.37
|
)
|
|
Weighted average shares outstanding, basic and diluted (2)
|
1,137
|
|
|
29,642
|
|
|
31,475
|
|
|
31,499
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 (Quarter ended)
|
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
|
(Unaudited)
|
|
Net revenues
|
$
|
2,567
|
|
|
$
|
2,632
|
|
|
$
|
2,019
|
|
|
$
|
1,784
|
|
|
Loss from operations
|
(3,606
|
)
|
|
(3,604
|
)
|
|
(3,867
|
)
|
|
(27,597
|
)
|
|
Net loss applicable to stockholders
|
(2,984
|
)
|
|
(4,916
|
)
|
|
(1,303
|
)
|
|
(27,052
|
)
|
|
Net loss per common share, basic and diluted (1)
|
$
|
(0.09
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
(0.85
|
)
|
|
Weighted average shares outstanding, basic and diluted
|
31,563
|
|
|
31,803
|
|
|
31,845
|
|
|
31,859
|
|
1)
Quarterly loss per share is based on the weighted average number of shares outstanding during the quarter. Because of changes in the number of shares outstanding during the quarters, due to the exercise of stock options and issuance of common stock, the sum of quarterly losses per share may not equal loss per share for the year.
2) As a result of the Merger with Infinity Corp., which consummated on April 14, 2014, the issued and outstanding common stock was canceled and reissued as common stock in the newly merged entity at a conversion ratio of
2.9
pre-Merger common stock to
1
post-Merger common stock. For the periods prior to the Merger, the above table reflects the common stock as converted to post-Merger common stock using this ratio.