1. Organization and nature of operations
TransCoastal Corporation (“TCC”), a Texas corporation, was formed on August 12, 1998 for the purpose of exploring, developing, producing and operating oil and natural gas properties primarily located in Texas. Effective January 1, 2011, TCC purchased CoreTerra Operating, LLC (“CTO”), a Texas limited liability company, for the primary purpose of operating oil and natural gas properties on its behalf. Collectively, TCC and its subsidiary, CTO, are referred to as the Company.
2. Summary of significant accounting policies
Basis of Presentation
The consolidation financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).
These consolidated financial statements were approved by management and available for issuance on May 14, 2013. Subsequent events have been evaluated through this date.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of TCC and its wholly owned subsidiary, CTO. All intercompany transactions and balances have been eliminated in consolidation.
Fair Value Measurements
The Company has adopted and follows ASC 820, Fair Value Measurements and Disclosures, for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC 820 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by ASC 820 are:
Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 — Inputs (other than quoted market prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Valuation of instruments includes unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities.
As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
2. Summary of significant accounting policies (continued)
Fair Value Measurements (continued)
transaction between market participants at the measurement date. The carrying amounts of the Company’s financial assets and liabilities, such as cash and cash equivalents, oil and natural gas sales receivable, and accounts payable and accrued liabilities, approximate their fair values because of the short maturity of these instruments.
Cash and Cash Equivalents
The Company considers all highly-liquid debt instruments with original maturities of three months or less to be cash equivalents. As of December 31, 2012 and 2011, the Company held approximately $16 and $11, respectively, in cash equivalents.
The Company maintains its cash balances in financial institutions which are insured by the Federal Deposit Insurance Corporation (“FDIC”). The interest bearing cash accounts maintain FDIC coverage of up to $250 per institution. Non-interest bearing accounts are fully covered subject to the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”). This provision of the Act is scheduled to expire on December 31, 2012. As of December 31, 2012 and 2011, the Company did not have any amounts in excess of its FDIC coverage.
Accounts Receivable, Net
Accounts receivable, net is comprised of billings for services as the operator on certain wells, that TCC has no working interest in, and accrued natural gas and crude oil sales. The Company performs ongoing credit evaluations of its customers’ and extends credit to virtually all of its customers. Credit losses to date have not been significant and have been within management’s expectations. In the event of complete non-performance by the Company’s customers, the maximum exposure to the Company is the outstanding accounts receivable, net balance at the date of non-performance. The amounts billed to third parties for services as the operator have rights of offset against revenues generated from the sale of oil and gas commodities. For the years ended December 31, 2012 and 2011, the Company had no bad debt expense.
Derivative Activities
The Company utilized oil and natural gas derivative contracts to mitigate it’s exposure to commodity price risk associated with its future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors or collars. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company does not apply hedge accounting to its oil and natural gas derivative contracts and accordingly the changes in the fair value of these instruments are recognized in the consolidated statements of operations in the period of change.
The Company’s derivative instruments are issued to manage the price risk attributable to our expected natural gas and oil production. While there is risk that the financial benefit of rising natural gas and oil prices may not be captured, Company management believes the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. Every unsettled derivative instrument is recorded on the accompanying consolidated balance sheets as either an asset or a liability measured at its fair
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
2. Summary of significant accounting policies (continued)
Derivative Activities (continued)
value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from natural gas and oil derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.
Realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative gains or (losses) in the accompanying consolidated statements of operations.
Oil and Gas Natural Gas Properties
The Company uses the full-cost method of accounting for its oil and natural gas producing activities as further defined under ASC 932, Extractive Activities - Oil and natural gas. Under these provisions, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits and other internal costs directly identified with these activities, and oil and natural gas property acquisitions are capitalized. All costs related to production, general corporate overhead or similar activities are expensed as incurred.
Proved properties are amortized using the units of production method (“UOP”). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced at year end by the cost of those reserves.
The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs (future costs to access and develop reserves) and asset retirement costs that are not already included in oil and natural gas property, less related salvage value.
The cost of unproved properties and properties under development are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed in service. Geological and geophysical costs not associated with specific properties are recorded to proved properties. Unproved properties and properties under development are reviewed for impairment at least quarterly. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. As of December 31, 2012 and 2011, no unproved properties or properties under development were included in the oil and natural gas properties of the accompanying consolidated financial statements.
Proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities in a particular country are sold, in which case a gain or loss is recognized in income. For the years ended December 31, 2012 and 2011, no gain or loss from the sale or disposition of oil and natural gas properties occurred.
Under the full-cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10 percent per annum based on industry standards and adjusted for cash flow hedges. Estimated future net cash flows exclude future cash outflows associated with settling accrued asset retirement obligations. Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the accompanying consolidated statements of operations. For the years ended December 31, 2012 and 2011, no impairment charge occurred.
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
2. Summary of significant accounting policies (continued)
Oil and Gas Natural Gas Properties (continued)
During the years ended December 31, 2012 and 2011, the Company determined $111 and $0, respectively, of interest costs were incurred during the development period of our wells.
Other Property and Equipment
Other property and equipment, which includes buildings, field equipment, vehicles, and office equipment, is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Vehicles and office equipment are generally depreciated over a useful life of five or six years, field equipment is generally depreciated over a useful life of ten years and buildings are generally depreciated over a useful life of twenty years.
Impairment of Long-Lived Assets
The Company assesses the impairment of long-lived assets when circumstances indicate that the carrying value may not be recoverable. The Company determines if impairment has occurred through adverse changes. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. For the years ended December 31, 2012 and 2011, no circumstances indicated an unrecoverable carrying value of the long-lived assets.
Goodwill
Goodwill was generated as part of the CTO acquisition during the year ended December 31, 2011 and represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition. Goodwill is not amortized; rather, it is tested for impairment annually and when events or changes in circumstances indicate that fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. As of December 31, 2012 and 2011, the Company had only one reporting unit. To assess impairment, the Company has the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the book value. Absent a qualitative assessment, or, through the qualitative assessment, if the Company determines it is more likely than not that the fair value of the reporting unit is less than the book value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the book value, the recorded goodwill is impaired to its implied fair value with a charge to operating expenses. For the years ended December 31, 2012 and 2011, no impairment charge occurred.
Asset Retirement Obligations
The Company follows the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted as part of the oil and natural gas property. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company’s asset retirement obligations relate to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties.
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
2. Summary of significant accounting policies (continued)
Asset Retirement Obligations (continued)
Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under ASC 820. Additionally, because of the subjectivity of assumptions and the relatively long lives of the Company’s wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.
Revenue Recognition and Natural Gas Imbalances
The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells. The Company will also enter into physical contract sale agreements through its normal operations. These contracts are not considered derivative contracts by the Company in accordance with the normal purchases and normal sales provision of ASC 815-10-15.
Gas imbalances are accounted for using the sales method. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. However, the Company has no history of significant gas imbalances.
Drilling Revenue
The Company follows the provisions of ASC 605-45, Revenue Recognition – Principal Agent Considerations, which requires the Company to record drilling revenues at net given such services are on behalf of third party oil and natural gas property operators. The Company does not own a participating interest in the wells for which drilling revenues, net are recorded. During the year ended December 31, 2012, the Company recognized net drilling revenues of approximately $2,716, which is included in the accompanying consolidated statements of operations. The Company had no such drilling revenues during the year ended December 31, 2011. The following table presents the gross drilling revenues and drilling expenses of the Company for the year ended December 31, 2012:
| Gross drilling revenues | | $ | 11,446 | |
| Gross drilling expenses | | | (8,700 | ) |
| | | | | |
| Total drilling revenues, net | | $ | 2,746 | |
Lease Operating Expenses
Lease operating expenses represents severance and production taxes, field personnel salaries, saltwater disposal, ad valorem taxes, repairs and maintenance, and other operating expenses. Lease operating expenses are expensed as incurred.
Sales-Based Taxes
The Company incurs severance tax on the sale of its production which is generated in Texas. These taxes are reported on a gross basis and are included in lease operating expenses within the accompanying consolidated statements of operations. Sales-based taxes for the years ended December 31, 2012 and 2011 were approximately $177 and $168, respectively.
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
2. Summary of significant accounting policies (continued)
Income Taxes
The Company complies with GAAP which requires an asset and liability approach to financial reporting for income taxes. Deferred income tax assets and liabilities are computed for differences between the financial statement and tax basis of assets and liabilities that will result in future taxable or deductible amounts, based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established, when necessary, to reduce deferred income tax assets to the amount expected to be realized.
The Company is required to determine whether its tax positions are more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The tax benefit recognized is measured as the largest amount of benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement with the relevant taxing authority. De-recognition of a tax benefit previously recognized results in the Company recording a tax liability that reduces ending retained earnings. Based on its analysis, the Company has determined that it has not incurred any liability for unrecognized tax benefits as of December 31, 2012 and 2011.
The Company’s conclusions may be subject to review and adjustment at a later date based on factors including, but not limited to, on-going analyses of and changes to tax laws, regulations and interpretations thereof. The Company recognizes interest and penalties related to unrecognized tax benefits in interest expense and other expenses, respectively. No interest expense or penalties have been recognized as of December 31, 2012 and 2011 and for the years then ended.
The Company files an income tax return in the U.S. federal jurisdiction, and may file income tax returns in various U.S. states and foreign jurisdictions. Generally, the Company is subject to income tax examinations by major taxing authorities since 2009.
The Company may be subject to potential examination by U.S. federal, U.S. states or foreign jurisdiction authorities in the areas of income taxes. These potential examinations may include questioning the timing and amount of deductions, the nexus of income among various tax jurisdictions and compliance with U.S. federal, U.S. state and foreign tax laws. The Company’s management does not expect that the total amount of unrecognized tax benefits will materially change over the next twelve months.
Use of Estimates
The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
The Company’s estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
2. Summary of significant accounting policies (continued)
Use of Estimates (continued)
with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.
3. Fair value measurements
The following table presents information about the Company’s assets and liabilities measured at fair value as of December 31, 2012:
| | | | | | | | | | | | Balance as of | |
| | | | | | | | | | | | December 31, | |
| | | Level 1 | | | Level 2 | | | Level 3 | | | 2012 | |
Assets (at fair value): | | | | | | | | | | | | |
| Money market mutual fund | | $ | 16 | | | $ | | | | $ | | | | $ | 16 | |
| Derivative assets | | | | | | | 28 | | | | | | | | 28 | |
| Total assets (at fair value) | | $ | 16 | | | $ | 28 | | | $ | | | | $ | 44 | |
| | | | | | | | | | | | | |
Liabilities (at fair value): | | | | | | | | | | | | |
| Derivative liabilities | | $ | | | | $ | 6 | | | $ | | | | $ | 6 | |
| Asset retirement obligations | | | | | | | | | | | 877 | | | | 877 | |
| Total liabilities (at fair value) | | $ | | | | $ | 6 | | | $ | 877 | | | $ | 883 | |
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
3. Fair value measurements (continued)
The following table presents information about the Company’s assets and liabilities measured at fair value as of December 31, 2011:
| | | | | | | | | | | | Balance as of | |
| | | | | | | | | | | | December 31, | |
| | | Level 1 | | | Level 2 | | | Level 3 | | | 2011 | |
Assets (at fair value): | | | | | | | | | | | | |
| Money market mutual fund | | $ | 11 | | | $ | | | | $ | | | | $ | 11 | |
| Derivative assets | | | | | | | 255 | | | | | | | | 255 | |
| Total assets (at fair value) | | $ | 11 | | | $ | 255 | | | $ | | | | $ | 266 | |
| | | | | | | | | | | | | | | | | |
Liabilities (at fair value): | | | | | | | | | | | | | | | | |
| Asset retirement obligations | | $ | | | | $ | | | | $ | 838 | | | $ | 838 | |
Effective January 1, 2011, TCC acquired 100% of the member interests of CTO for a cash consideration of approximately $590. Through this acquisition, TCC assumed various assets and liabilities as part of the purchase. The consideration exchanged for assets was derived using the asset approach to calculate the asset’s, and related liabilities, fair-value shortly before January 1, 2011 and was completed to provide a return to the investors of the TCC. Goodwill of approximately $485 was recognized as a result of this acquisition and is calculated as the excess of the consideration paid over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. It specifically includes the expected synergies and other benefits the Company believes will result from the Company’s operational experience. The following table presents a summary of the fair value of assets and liabilities acquired at the January 1, 2011 in accordance with ASC 805-10, Business Combinations:
| Fair value of assets acquired and liabilities assumed | | | | |
| Cash and cash equivalents | | $ | 163 | |
| Other current assets | | | 4 | |
| Other non-current assets | | | 100 | |
| Other property and equipment | | | 41 | |
| Accounts payable and accrued liabilities | | | (203 | ) |
| Goodwill | | | 485 | |
| Total fair value of assets acquired and liabilities assumed, net | | $ | 590 | |
| | | | | |
| Total cash consideration paid | | $ | 590 | |
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
5. Oil and natural gas properties
The following tables present a summary of the Company’s oil and natural gas properties at December 31, 2012 and 2011:
| | | 2012 | | | 2011 | |
| | | | | | | |
| Proved-developed producing properties | | $ | 4,845 | | | $ | 3,194 | |
| Proved-developed non producing properties | | | 9,287 | | | | 5,341 | |
| Proved-undeveloped properties | | | 9,620 | | | | 12,977 | |
| Less: Accumulated depletion | | | (1,541 | ) | | | (1,177 | ) |
| Total oil and natural gas properties, net of accumulated depletion | | $ | 22,211 | | | $ | 20,335 | |
On June 15, 2011, the Company entered into a purchase agreement with a privately owned company to purchase 100% of the working interests and various royalty interests ranging from 75.00%-89.06% of wells located in Gray County, Texas for a cash consideration of approximately $616. The consideration exchanged for assets was derived using the asset approach to calculate the asset’s, and related liabilities, fair-value shortly before June 15, 2011 and was completed to provide a return to the investors of the Company. The following table presents a summary of the fair value of assets and liabilities acquired at the Roll-up Date in accordance with ASC 805-10, Business Combinations:
| Fair value of assets acquired and liabilities assumed | | | |
| Proved oil and natural gas properties | | $ | 889 | |
| Asset retirement obligations | | | (273 | ) |
| Total fair values of assets acquired and liabilities assumed, net | | $ | 616 | |
| | | | | |
| Total cash consideration paid | | $ | 616 | |
On October 29, 2012, the Company obtained 100% of the working interests and 75% of the revenue interests of wells located in Gray County, Texas as settlement for notes receivable, related parties issued on March 31, 2012 and June 30, 2012 for approximately $1,477. The following table presents a summary of the assets and liabilities obtained:
| Value of assets and liabilities obtained | | | |
| Proved oil and natural gas properties | | $ | 1,488 | |
| Asset retirement obligations | | | (11 | ) |
| Total assets and liabilities obtained | | $ | 1,477 | |
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
6. Other property and equipment
The following table presents a summary of the Company’s other property and equipment at December 31, 2012 and 2011:
| | | 2012 | | | 2011 | |
| | | | | | | |
| Field equipment | | $ | 322 | | | $ | 322 | |
| Vehicles | | | 422 | | | | 394 | |
| Office equipment | | | 245 | | | | 245 | |
| Buildings | | | 130 | | | | 130 | |
| Land | | | 13 | | | | 13 | |
| Less: Accumulated depreciation | | | (566 | ) | | | (406 | ) |
| Total other property and equipment, net of accumulated depreciation | | $ | 566 | | | $ | 698 | |
7. Asset retirement obligations
The Company has recognized the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties. The present value of the estimated asset retirement obligations has been capitalized as part of the carrying amount of the related oil and natural gas properties. The liability has been accreted to its present value as of the end of each period. At December 31, 2012 and 2011, the Company evaluated 213 and 210 wells, and has determined a range of abandonment dates between December 2012 and December 2051.
The following table represents a reconciliation of the asset retirement obligations for the years ended December 31, 2012 and 2011:
| | | 2012 | | | 2011 | |
| | | | | | | |
| Asset retirement obligations, start of year | | $ | 838 | | | $ | 481 | |
| Additions to asset retirement obligation | | | 1 | | | | 332 | |
| Accretion of discount | | | 38 | | | | 25 | |
| Asset retirement obligations, end of year | | $ | 877 | | | $ | 838 | |
On May 19, 2011, as amended from time to time through February 11, 2013, the Company entered into a loan agreement (the “Agreement”) with Green Bank with an initial borrowing base of $15,000,000 and amended to $16,500,000 on February 11, 2013. The Agreement is collateralized by essentially all of the oil and natural gas related assets of the Company, contains personal guarantees from the principal officers, and requires compliance with certain financials covenants. Additionally, the Agreement bears interest at the prime rate minus 0.01%, but not less than 4.99%. Interest payments are due monthly with all principal and any unpaid interest being due on July 1, 2014. The interest rate was 4.99% at December 31, 2012 and 2011. Additionally, in accordance with the Agreement, for the period from March 1, 2012 through September 30, 2012, monthly borrowing base reductions of $125 occurred automatically on the first day of each month. Effective October 1, 2012, the monthly borrowing base
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
8. Notes payable (continued)
reduction increased to $150 through January 15, 2013. The monthly borrowing base reductions were amended to $0 on February 11, 2013.
As of December 31, 2012 and 2011, the Company had an outstanding principal balance due to Green Bank of approximately $15,400 and $15,565, respectively, and approximately $0 and $133, respectively, of accrued interest, which is included in the accounts payable and accrued liabilities of the accompanying consolidated balance sheets. As of December 31, 2012 and 2011, the current maturities of the outstanding principal balance were $150 and $15,565, respectively. The Company was in compliance with all financial covenants as of December 31, 2012. The Company was not in compliance with all financial covenants as of December 31, 2011.
Deferred tax assets are determined based on the difference between financial statement and tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The components of the deferred taxes as of December 31, 2012 and 2011 are as follows:
| | | 2012 | | | 2011 | |
| Deferred tax assets | | | | | | |
| Federal net operating loss carryforward | | $ | 1,649 | | | $ | 1,456 | |
| Accrued interest | | | | | | | 45 | |
| Asset retirement obligations | | | 298 | | | | 280 | |
| Shares to be issued | | | | | | | 459 | |
| Total deferred tax assets | | | 1,947 | | | | 2,240 | |
| Deferred tax liabilities | | | | | | | | |
| Depletion and Depreciation | | | 217 | | | | 177 | |
| Net deferred tax asset, before valuation allowance | | | 1,730 | | | | 2,063 | |
| Valuation allowance | | | (1,730 | ) | | | (2,063 | ) |
| Net deferred tax asset | | $ | | | | $ | | |
As of December 31, 2012 and 2011, the Company had net operating loss (“NOL”) carryforwards of approximately $3,270 and $4,424, respectively, which can be utilized in future years. These NOLs, if not used, will expire between 2024 and 2031. A valuation allowance has been established for the full amount of the tax asset since it is more likely than not that the deferred tax asset will not be realized.
10. Shareholders’ equity (share and per share amounts shown in whole numbers)
At December 31, 2012 and 2011, the authorized capital stock of the Company consisted of 50,000,000 shares of voting common stock with a par value of $0.0001 per share and 5,000,000 and 0, respectively, shares of preferred stock with a par value of $.001 per share. As of December 31, 2012 and 2011, there were 22,634,091 and 22,069,403, respectively, common shares issued and outstanding and 37,500 and 0, respectively, preferred shares issued and outstanding. As of December 31, 2011 there were 600,000 common shares to be issued.
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
10. Shareholders’ equity (share and per share amounts shown in whole numbers) (continued)
During the year ended December 31, 2011, the Company incurred stock based compensation expenses of approximately $1,515. As of December 31, 2011, stock certificates for $1,350 of the stock based compensation had not yet been issued. These amounts are reflected as common stock to be issued in the accompanying consolidated balance sheets.
During the year ended December 31, 2012, the shareholders’ due the $1,350 of stock based compensation forfeited their right to the shares, which is included in forfeiture of common stock to be issued in the accompanying consolidated statements of changes in shareholders’ equity and members’ interest.
During the year ended December 31, 2012, the Company issued 564,888 common shares to certain employees and vendors for services to the Company. The Company valued those services at approximately $215.
During the year ended December 31, 2012, the Company issued 37,500 shares of series A convertible preferred stock at 8%, payable annually, for $75,000. The preferred stock may be converted any time after the first year at the request of the shareholder or the Company into two (2) shares of common stock of TCC and one (1) warrant that will allow the holder, for a period of three years from the date of issue, to acquire one additional share of TCC common stock for each warrant at a purchase price of $3.50 per share.
11. Derivative contracts, at fair value
In the normal course of business, the Company utilizes derivative contracts in connection with its oil and natural gas operations. Derivative contracts are subject to additional risks that can result in additional losses. The Company’s derivative activities and exposure to derivative contracts are classified by the following primary underlying risks: commodity price. In addition to its primary underlying risks, the Company is also subject to additional counterparty risk due to inability of its counterparties to meet the terms of their contracts.
Options
The Company is subject to commodity price risk in the normal course of pursuing its investment objectives. The Company may enter into options to speculate on the price movements of the commodity underlying the option or for use as an economic hedge against oil and natural gas production. Option contracts purchased give the Company the right, but not the obligation, to buy or sell within a limited time, a commodity at a contracted price that may also be settled in cash, based on differentials between specified indices or prices. For some OTC options, the Company may be exposed to counterparty risk from the potential that a seller of an option contract does not sell or purchase the underlying asset as agreed under the terms of the option contract. The maximum risk of loss from counterparty risk to the Company is the fair value of the contracts and the premiums paid to purchase its open option contracts. In these instances, the Company considers the credit risk of the intermediary counterparty to its option transactions in evaluating potential credit risk.
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
11. Derivative contracts, at fair value (continued)
Swap Contracts
Generally, a swap contract is an agreement that obligates two parties to exchange a series of cash flows at specified intervals based upon or calculated by reference to changes in specified prices or rates for a specified notional amount of the underlying assets. The payment flows are usually netted against each other, with the difference being paid by one party to the other. During the term of the swap contracts, changes in value are recognized as unrealized gains or losses by marking the contracts at fair value. Additionally, the Company records a realized gain (loss) when a swap contract is terminated and when periodic payments are received or made at the end of each measurement period. The fair value of open swaps reported in the balance sheet may differ from that which would be realized in the event the Company terminated its position in the contracts. Risks may arise as a result of the failure of the counterparty to the swap contract to comply with the terms of the swap contract.
The loss incurred by the failure of a counterparty is generally limited to the aggregate fair value of swap contracts in an unrealized gain position as well as any collateral posted with the counterparty. The risk is mitigated by having a master netting arrangement between the Company and the counterparty and by the posting of collateral by the counterparty to the Company to cover the Company’s exposure to the counterparty. Therefore, the Company considers the creditworthiness of each counterparty to a swap contract in evaluating potential credit risk.
Underlying Exposure
At December 31, 2012, the volume of the Company’s derivative activities based on their notional amounts and number of contracts, categorized by primary underlying risk, are as follows:
| | | Long Exposure | | | Short Exposure | |
Primary underlying risk | | Notional Amounts(a) | | | Number of Contracts(b) | | | Notional Amounts(a) | | | Number of Contracts(b) | |
| Commodity price | | | | | | | | | | | | |
| Swap | | $ | | | | | | | | $ | 2,751 | | | | 2 | |
| Options | | | 354 | | | | 1 | | | | 266 | | | | 1 | |
| | | $ | 354 | | | | 1 | | | $ | 3,017 | | | | 3 | |
| | (a) | Notional amounts presented for contracts are based on the fair value of the underlying commodity as if the contracts were exercised at December 31, 2012. |
| | (b) | Number of contracts is presented in whole numbers. |
At December 31, 2011, the volume of the Company’s derivative activities based on their notional amounts and number of contracts, categorized by primary underlying risk, are as follows:
| | | Long Exposure | | | Short Exposure | |
Primary underlying risk | | Notional Amounts(a) | | | Number of Contracts(b) | | | Notional Amounts(a) | | | Number of Contracts(b) | |
| Commodity price | | | | | | | | | | | | |
| Options | | $ | | | | | | | | $ | 4,320 | | | | 3 | |
| | (a) | Notional amounts presented for contracts are based on the fair value of the underlying commodity as if the contracts were exercised at December 31, 2011. |
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
11. Derivative contracts, at fair value (continued)
| | (b) | Number of contracts is presented in whole numbers. |
Impact of Derivatives on the Consolidated Balance Sheets and Consolidated Statements of Operations
The following table identifies the fair value amounts of derivative instruments included in the accompanying consolidated balance sheets as derivative assets and derivative liabilities, categorized by primary underlying risk, at December 31, 2012. Balances are presented on a gross basis, prior to the application of the impact of counterparty and collateral netting.
| | | Derivative Assets | | | Derivative Liabilities | | | Amount of gain (loss) | |
| Primary underlying risk | | | | | | | | | |
| Commodity price | | | | | | | | | |
| Swaps | | $ | 32 | | | $ | | | | $ | 42 | |
| Options | | | 16 | | | | (26 | ) | | | (260 | ) |
| Gross total | | | 48 | | | | (26 | ) | | | (218 | ) |
| Less: Master netting arrangements | | | 26 | | | | (26 | ) | | | | |
| Total | | $ | 22 | | | $ | | | | $ | (218 | ) |
The following table identifies the fair value amounts of derivative instruments included in the accompanying consolidated balance sheets as derivative assets, categorized by primary underlying risk, at December 31, 2011. Balances are presented on a gross basis, prior to the application of the impact of counterparty and collateral netting.
| | | Derivative Assets | | | Derivative Liabilities | | | Amount of loss | |
| Primary underlying risk | | | | | | | | | |
| Commodity price | | | | | | | | | |
| Options | | $ | 255 | | | $ | | | | $ | (129 | ) |
The following table identifies the net gain and (loss) amounts included in the accompanying consolidated statements of operations as derivative losses for the year ended December 31, 2012.
| | | Realized gain (loss) | | | Unrealized gain (loss) | | | Total | |
| Primary underlying risk | | | | | | | | | |
| Commodity price | | | | | | | | | |
| Swaps | | $ | 21 | | | $ | 21 | | | $ | 42 | |
| Options | | | (342 | ) | | | 82 | | | | (260 | ) |
| Total | | $ | (321 | ) | | $ | 103 | | | $ | (218 | ) |
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
11. Derivative contracts, at fair value (continued)
Impact of Derivatives on the Consolidated Balance Sheets and Consolidated Statements of Operations (continued)
The following table identifies the net loss amounts included in the accompanying consolidated statements of operations as derivative losses for the year ended December 31, 2011.
| | | Realized loss | | | Unrealized loss | | | Total | |
| Primary underlying risk | | | | | | | | | |
| Commodity price | | | | | | | | | |
| Options | | $ | 48 | | | $ | 81 | | | $ | 129 | |
12. Related Party Transactions
During the years ended December 31, 2012 and 2011, the Company paid consulting fees of approximately $0 and $498 directly to companies owned by members of Company management or directly to members of Company management. These consulting fees are included in the professional fees on the accompanying consolidated statements of operations.
During the year ended December 31, 2012, the Company issued notes receivable, related party of approximately $1,477 to companies owned by members of the Company management or directly to members of Company management. On October 29, 2012, these notes receivable, related party, were settled through the assignment of certain working and revenue interests of wells located in Gray County, Texas to the Company. This acquisition of oil and natural gas properties is further described in Note 5.
During the year ended December 31, 2012, the Company was issued a note payable, related party of approximately $125 from a member of the Company management.
13. Commitment and Contingencies
Oil and Natural Gas Regulations
The Company is subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes that it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, environmental matters are subject to regulation by various federal and state agencies.
Legal Proceedings
The Company is subject to various legal proceedings and claims that arise in the ordinary course of business. In the opinion of management the amount of any ultimate liability with respect to these actions will not materially affect the Company’s consolidated balance sheets or consolidated results of operations.
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
13. Commitment and Contingencies (continued)
Lease Commitments
The Company leases its primary office space under an operating lease which expires in 2014. Lease expense was approximately $189 and $187, respectively, for the years ended December 31, 2012 and 2011. Aggregate future minimum annual rental payments in the years subsequent to December 31, 2012 are as follows:
| Year ending December 31, | | | | |
| 2013 | | $ | 193 | |
| 2014 | | | 181 | |
| Total future minimum rental payments | | $ | 374 | |
For the years ended December 31, 2012 and 2011, revenues from the Company’s 33 and 32, respectively, producing leases ranged from approximately 0.1% to 17.7% and 0.1% to 15.8%, respectively, of total oil, natural gas, and related product sales. These 33 and 32, respectively, leases are all located in the Texas counties of Pampa, Stevens and Montague.
For the years ended December 31, 2012 and 2011, the oil and natural gas produced by the Company is sold and marketed to 9 and 8, respectively, purchasers. Oil sales to two purchasers accounted for 92.8% and 94.1%, respectively, of the oil sales. Individually, the two purchasers accounted for approximately 71.1% and 21.7% and 62.4% and 31.7%, respectively. Natural gas sales to three purchasers account for 91.6% and 95.1%, respectively, of the natural gas sales. Individually, the three purchasers accounted for approximately 55.4%, 20.8% and 15.4% and 45.7%, 28.1%, and 21.2%, respectively. Accordingly, the Company’s entire oil and natural gas sales receivable balance at December 31, 2012 and 2011 was comprised of amounts due from its 9 and 8, respectively, purchasers. Oil and natural gas sales receivable are included in the accounts receivable, net on the accompanying consolidated balance sheets.
15. Subsequent Events
On March 18, 2013, and then amended on April 24, 2013, the Company executed an acquisition agreement with Claimsnet.com Inc. (“Claimsnet”), a Delaware corporation. In the acquisition agreement, Claimsnet agreed to purchase all of the Company’s issued and outstanding shares of common stock. The purchase price is in the form of Series F Convertible Preferred stock in the form of certificates evidencing newly issued shares of Claimsnet. Claimsnet is pursuing a change of name to TransCoastal Corporation (“New TCC”) and the Company, which would now be a subsidiary of New TCC, would change its name to TransCoastal Corporation of Texas (“TCCT”). The following selected unaudited pro forma consolidated financial information of New TCC and TCCT is prepared to illustrate the effect of the acquisition of TCC’s common stock, whereby TCCT is subject to predecessor accounting. The unaudited pro forma consolidated balance sheets give effect to the transaction as if it occurred on December 31, 2012 and 2011. The unaudited pro forma consolidated statements of operations give effect to the transaction as if it occurred at the beginning of the year ended December 31, 2012 and 2011.
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
15. Subsequent Events (continued)
TRANSCOASTAL CORPORATION AND SUBSIDIARY
PRO FORMA CONSOLIDATED BALANCE SHEET
(AMOUNTS SHOWN IN THOUSANDS, EXCEPT SHARE AND PER SHARE INFORMATION)
| | | NEW TCC | | | TCCT | | | PRO-FORMA ADJUST | | | | TOTAL | |
| ASSETS | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Current assets | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 41 | | | $ | 127 | | | $ | (41 | ) | (A) | | $ | 127 | |
| Accounts receivable, net | | | 314 | | | | 584 | | | | (314 | ) | (A) | | | 584 | |
| Current derivative assets | | | | | | | 28 | | | | | | | | | 28 | |
| Other current assets | | | 31 | | | | 20 | | | | (31 | ) | (A) | | | 20 | |
| Total current assets | | | 386 | | | | 759 | | | | (386 | ) | | | | 759 | |
| | | | | | | | | | | | | | | | | | |
| Oil and natural gas properties and other property and equipment | | | | | | | | | | | | | | | | | |
| Oil and natural gas properties, full cost method, net of accumulated depletion | | | | | | | 22,211 | | | | | | | | | 22,211 | |
| Other property and equipment, net of accumulated depreciation | | | | | | | 566 | | | | | | | | | 566 | |
| Total oil and natural gas properties and other equipment, net | | | | | | | 22,777 | | | | | | | | | 22,777 | |
| | | | | | | | | | | | | | | | | | |
| Other assets | | | | | | | | | | | | | | | | | |
| Goodwill | | | | | | | 485 | | | | | | | | | 485 | |
| Other non-current assets | | | | | | | 105 | | | | | | | | | 105 | |
| Total other assets | | | | | | | 590 | | | | | | | | | 590 | |
| Total assets | | $ | 386 | | | $ | 24,126 | | | $ | (386 | ) | | | $ | 24,126 | |
| | | | | | | | | | | | | | | | | | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Current liabilities | | | | | | | | | | | | | | | | | |
| Accounts payable and accrued liabilities | | $ | 611 | | | $ | 695 | | | $ | (611 | ) | (A) | | $ | 695 | |
| Notes payable, related party | | | | | | | 125 | | | | | | | | | 125 | |
| Current asset retirement obligations | | | | | | | 12 | | | | | | | | | 12 | |
| Current maturities of notes payable | | | 1,345 | | | | 150 | | | | (1,345 | ) | (A) | | | 150 | |
| Total current liabilities | | | 1,956 | | | | 982 | | | | (1,956 | ) | | | | 982 | |
| | | | | | | | | | | | | | | | | | |
| Long-term liabilities | | | | | | | | | | | | | | | | | |
| Notes payable | | | | | | | 15,250 | | | | | | | | | 15,250 | |
| Deferred revenues | | | 3 | | | | | | | | (3 | ) | (A) | | | | |
| Asset retirement obligations | | | | | | | 865 | | | | | | | | | 865 | |
| Derivative liabilities | | | | | | | 6 | | | | | | | | | 6 | |
| Total long-term liabilities | | | 3 | | | | 16,121 | | | | (3 | ) | | | | 16,121 | |
| | | | | | | | | | | | | | | | | | |
| Commitments and contingencies | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Shareholders’ equity (deficit) | | | | | | | | | | | | | | | | | |
| Preferred stock, $.001 par value; 5,000,000 shares authorized; 37,500 shares issued and outstanding | | | | | | | | | | | | | | | | | |
| Common stock, $.0001 par value; 50,000,000 shares authorized; 22,643,091 shares issued and outstanding | | | 36 | | | | 2 | | | | (36 | ) | (A) | | | 2 | |
| Additional paid-in-capital | | | 44,895 | | | | 45,301 | | | | (44,895 | ) | (A) | | | 45,301 | |
| Accumulated deficit | | | (46,504 | ) | | | (38,280 | ) | | | 46,504 | | (A) | | | (38,280 | ) |
| Total shareholders’ equity (deficit) | | | (1,573 | ) | | | 7,023 | | | | 1,573 | | | | | 7,023 | |
| | | | | | | | | | | | | | | | | | |
| Total liabilities and shareholders’ equity | | $ | 386 | | | $ | 24,126 | | | $ | (386 | ) | | | $ | 24,126 | |
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
15. Subsequent Events (continued)
TRANSCOASTAL CORPORATION AND SUBSIDIARY
PRO FORMA CONSOLIDATED BALANCE SHEET
(AMOUNTS SHOWN IN THOUSANDS, EXCEPT SHARE AND PER SHARE INFORMATION) | | | NEW TCC | | | TCCT | | | PRO-FORMA ADJUST | | | | TOTAL | |
| ASSETS | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Current assets | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 40 | | | $ | 336 | | | $ | (40 | ) | (A) | | $ | 336 | |
| Accounts receivable, net | | | 318 | | | | 273 | | | | (318 | ) | (A) | | | 273 | |
| Current derivative assets | | | | | | | 85 | | | | | | | | | 85 | |
| Other current assets | | | 32 | | | | 22 | | | | (32 | ) | (A) | | | 22 | |
| Total current assets | | | 390 | | | | 716 | | | | (390 | ) | | | | 716 | |
| | | | | | | | | | | | | | | | | | |
| Oil and natural gas properties and other property and equipment | | | | | | | | | | | | | | | | | |
| Oil and natural gas properties, full cost method, net of accumulated depletion | | | | | | | 20,335 | | | | | | | | | 20,335 | |
| Other property and equipment, net of accumulated depreciation | | | 1 | | | | 698 | | | | (1 | ) | (A) | | | 698 | |
| Total oil and natural gas properties and other equipment, net | | | 1 | | | | 21,033 | | | | (1 | ) | | | | 21,033 | |
| | | | | | | | | | | | | | | | | | |
| Other assets | | | | | | | | | | | | | | | | | |
| Goodwill | | | | | | | 485 | | | | | | | | | 485 | |
| Derivative assets | | | | | | | 170 | | | | | | | | | 170 | |
| Other non-current assets | | | | | | | 100 | | | | | | | | | 100 | |
| Total other assets | | | | | | | 755 | | | | | | | | | 755 | |
| Total assets | | $ | 391 | | | $ | 22,504 | | | $ | (391 | ) | | | $ | 22,504 | |
| | | | | | | | | | | | | | | | | | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Current liabilities | | | | | | | | | | | | | | | | | |
| Accounts payable and accrued liabilities | | $ | 516 | | | $ | 567 | | | $ | (516 | ) | (A) | | $ | 567 | |
| Current asset retirement obligations | | | | | | | 13 | | | | | | | | | 13 | |
| Current maturities of notes payable | | | 1,195 | | | | 15,565 | | | | (1,195 | ) | (A) | | | 15,565 | |
| Total current liabilities | | | 1,711 | | | | 16,145 | | | | (1,711 | ) | | | | 16,145 | |
| | | | | | | | | | | | | | | | | | |
| Long-term liabilities | | | | | | | | | | | | | | | | | |
| Notes payable | | | 50 | | | | | | | | (50 | ) | (A) | | | | |
| Common stock to be issued | | | | | | | 1,350 | | | | | | | | | 1,350 | |
| Deferred revenues | | | 4 | | | | | | | | (4 | ) | (A) | | | | |
| Asset retirement obligations | | | | | | | 825 | | | | | | | | | 825 | |
| Total long-term liabilities | | | 54 | | | | 2,175 | | | | (54 | ) | | | | 2,175 | |
| | | | | | | | | | | | | | | | | | |
| Commitments and contingencies | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Shareholders’ equity (deficit) | | | | | | | | | | | | | | | | | |
| Common stock, $.0001 par value; 50,000,000 shares authorized; 22,069,403 shares issued and outstanding | | | 35 | | | | 2 | | | | (35 | ) | (A) | | | 2 | |
| Additional paid-in-capital | | | 44,896 | | | | 43,661 | | | | (44,896 | ) | (A) | | | 43,661 | |
| Accumulated deficit | | | (46,305 | ) | | | (39,479 | ) | | | 46,305 | | (A) | | | (39,479 | ) |
| Total shareholders’ equity (deficit) | | | (1,374 | ) | | | 4,184 | | | | 1,374 | | | | | 4,184 | |
| | | | | | | | | | | | | | | | | | |
| Total liabilities and shareholders’ equity | | $ | 391 | | | $ | 22,504 | | | $ | (391 | ) | | | $ | 22,504 | |
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
15. Subsequent Events (continued)
TRANSCOASTAL CORPORATION AND SUBSIDIARY
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
(AMOUNTS SHOWN IN THOUSANDS, EXCEPT SHARE AND PER SHARE INFORMATION)
Year ended December 31, 2012
| | | NEW TCC | | | TCCT | | | PRO-FORMA ADJUST | | | | TOTAL | |
| Revenues | | | | | | | | | | | | | |
| Oil, natural gas, and related product sales | | $ | | | | $ | 3,682 | | | $ | | | | | $ | 3,682 | |
| Derivative losses | | | | | | | (218 | ) | | | | | | | | (218 | ) |
| Drilling revenue, net | | | | | | | 2,746 | | | | | | | | | 2,746 | |
| Other revenue | | | | | | | 298 | | | | | | | | | 298 | |
| Revenues – non oil and gas | | | 2,511 | | | | | | | | (2,511 | ) | (A) | | | | |
| Total revenues | | | 2,511 | | | | 6,508 | | | | (2,511 | ) | | | | 6,508 | |
| | | | | | | | | | | | | | | | | | |
| Cost of revenues | | | | | | | | | | | | | | | | | |
| Lease operating | | | | | | | 1,291 | | | | | | | | | 1,291 | |
| Depreciation, depletion and amortization | | | | | | | 535 | | | | | | | | | 535 | |
| Accretion of discount on asset retirement obligations | | | | | | | 38 | | | | | | | | | 38 | |
| Cost of non oil and gas revenues | | | 1,928 | | | | | | | | (1,928 | ) | (A) | | | | |
| Total cost of revenues | | | 1,928 | | | | 1,864 | | | | (1,928 | ) | | | | 1,864 | |
| | | | | | | | | | | | | | | | | | |
| Gross Profit | | | 583 | | | | 4,644 | | | | (583 | ) | | | | 4,644 | |
| | | | | | | | | | | | | | | | | | |
| Operating expenses | | | | | | | | | | | | | | | | | |
| Professional fees | | | | | | | 499 | | | | | | | | | 499 | |
| Payroll | | | | | | | 1,195 | | | | | | | | | 1,195 | |
| Stock based compensation | | | | | | | 213 | | | | | | | | | 213 | |
| Research and development | | | 14 | | | | | | | | (14 | ) | (A) | | | | |
| General and administrative | | | 745 | | | | 798 | | | | (745 | ) | (A) | | | 798 | |
| Total operating expenses | | | 759 | | | | 2,705 | | | | (759 | ) | | | | 2,705 | |
| | | | | | | | | | | | | | | | | | |
| Operating income (loss) | | | (176 | ) | | | 1,939 | | | | 176 | | | | | 1,939 | |
| | | | | | | | | | | | | | | | | | |
| Other income (expense) | | | | | | | | | | | | | | | | | |
| Interest income | | | | | | | 2 | | | | | | | | | 2 | |
| Interest expense | | | (23 | ) | | | (713 | ) | | | 23 | | (A) | | | (713 | ) |
| Other expense | | | | | | | (29 | ) | | | | | | | | (29 | ) |
| Total other income (expense) | | | (23 | ) | | | (740 | ) | | | 23 | | | | | (740 | ) |
| Net income (loss) | | $ | (199 | ) | | | 1,199 | | | $ | 199 | | | | | 1,199 | |
TRANSCOASTAL CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS SHOWN IN THOUSANDS)
15. Subsequent Events (continued)
TRANSCOASTAL CORPORATION AND SUBSIDIARY
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
(AMOUNTS SHOWN IN THOUSANDS, EXCEPT SHARE AND PER SHARE INFORMATION)
(UNAUDITED)
