The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under "risk factors" and elsewhere in this Annual Report on Form 10-K.
Cubic Energy, Inc. is an independent upstream energy company engaged in the development and production of, and exploration for, crude oil and natural gas. Our oil and gas assets and activities are concentrated exclusively in Louisiana and Texas.
Our corporate strategy with respect to our asset acquisition and development efforts was to position the Company in a low risk opportunity while building main stream high yield reserves. The acquisition of our Cotton Valley acreage in DeSoto and Caddo Parishes, Louisiana, put us in a reservoir rich environment both in the Cotton Valley and Bossier/Haynesville Shale formations, and gives us the potential to discover additional commercial horizons that can add value to the bottom line. We have had success on our acreage with wells drilled by achieving production from not only the Cotton Valley and Bossier/Haynesville Shale formations, but also the Hosston formations.
Summary Operating, Reserve and Other Data
The following table presents an unaudited summary of certain operating and oil and natural gas reserve data, and non-GAAP financial data for the periods indicated: Year ended June 30, 2013 2012 2011 2010 2009 Operating Data: Proved Reserves (Bcfe) 45.2 33.8 57.7 29.2 21.1 Production (Mcfe) 1,161,802 2,258,577 1,497,666 806,102 300,712 Producing wells at end of period, gross 64 60 58 40 43 Producing wells at end of period, net 13.41 13.52 13.47 11.81 21.44 Acreage, gross 13,123 13,123 13,239 13,594 14,466 Acreage, net 5,100 5,100 5,149 5,324 6,077 Production: Oil (Bbl) 863 1,100 1,444 1,364 1,681 Natural gas (Mcf) 1,141,474 2,244,315 1,481,430 792,433 279,516 Natural gas liquids (Bbl) 2,525 1,277 1,262 915 1,852 Total oil, gas and liquids (Mcfe) 1,161,802 2,258,577 1,497,666 806,102 300,712 Average daily (Mcfe) 3,183 6,188 4,103 2,208 824 Weighted Average Sales Prices: Oil (per Bbl) $ 90.00 $ 93.25 $ 83.13 $ 73.18 $ 66.52 Natural gas (per Mcf) $ 3.21 $ 3.01 $ 4.00 $ 4.21 $ 3.72 Natural gas liquids (per Bbl) $ 41.16 $ 66.78 $ 67.20 $ 53.34 $ 42.84 Natural gas equivalent (per Mcfe) $ 3.31 $ 3.07 $ 4.10 $ 4.32 $ 6.18 Selected Expenses per Mcfe: Production costs $ 0.65 $ 0.43 $ 0.60 $ 1.27 $ 3.98 Workover expenses (non-recurring) $ 0.04 $ 0.07 $ 0.01 $ 0.05 $ 0.12 Severance taxes $ 0.16 $ (0.06 ) $ 0.07 $ 0.15 $ 0.20 Other revenue deductions $ 0.76 $ 0.43 $ 0.56 $ 0.65 $ 0.27 Total lease operating expenses $ 1.61 $ 0.87 $ 1.24 $ 2.12 $ 4.57 General and administrative expenses: Non-cash stock-based compensation $ 0.05 $ 0.10 $ 0.38 $ 0.49 $ 1.28 Other general and administrative $ 1.96 $ 1.48 $ 1.72 $ 2.47 $ 5.17 Total general and administrative $ 2.01 $ 1.58 $ 2.10 $ 2.96 $ 6.45 Depreciation, depletion and amortization $ 2.80 $ 2.70 $ 2.48 $ 1.43 $ 2.55 40
Table of Contents RESULTS OF OPERATIONS
Comparison of Fiscal 2013 to Fiscal 2012
OIL AND GAS SALES decreased 45\% to $3,843,420 for fiscal 2013 from $6,939,999 for fiscal 2012 primarily due to decreased gas volumes resulting from the rapid depletion rate of our existing Haynesville Shale wells. This was mitigated by 3 new Cotton Valley horizontal wells that came online during fiscal 2013, all of which are operated by Indigo Minerals. The average price of natural gas was $3.21 per Mcfe for fiscal 2013, as compared to $3.01 per Mcfe for fiscal 2012.
Costs and Expenses
OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as "LEASE OPERATING EXPENSES" elsewhere herein) decreased 5\% to $1,872,186 (49\% of oil and gas sales) for fiscal 2013 from $1,972,223 (28\% of oil and gas sales) for fiscal 2012. This decrease was primarily due to a $95,618 decrease in other O&G deductions, which are costs passed-through to the Company by the purchaser of the Company's gas. The increase as a percentage of oil and gas sales was primarily due to no credit received in fiscal 2012 for severance taxes.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") decreased 35\% to $2,332,946 for fiscal 2013 from $3,572,260 in fiscal 2012. This decrease of $1,239,313 was primarily due to a decrease in legal fees of $1,010,171 incurred during fiscal 2012 due to the EXCO and BG arbitration and settlement. In addition there was a decrease in stock compensation of $236,295 created by the Company's reduced stock price and reduction in number of shares issued to directors.
DEPRECIATION, DEPLETION AND NON-LOAN RELATED AMORTIZATION ("DD&A") decreased 47\% to $3,248,260 in fiscal 2013 from $6,090,529 in fiscal 2012, primarily due to a decrease in the depletion percentage rate for fiscal 2013 of 2.51\% versus 6.27\% for fiscal 2012, which was primarily the result of an approximate 12.5 million Mcf increase to our reserves. This reduction was created by smaller full cost pool additions and a decreased depletion rate. The depletion rate is a result of a change in beginning reserves, full cost pool to deplete, accumulated depletion and annual production.
INTEREST EXPENSE, INCLUDING AMORTIZATION OF LOAN DISCOUNT decreased 68\% to $2,470,516 in fiscal 2013 from $7,729,992 in fiscal 2012. Our debt decreased as a result of the paydown with a portion of the funds received in the EXCO/BG settlement. We had total outstanding balances of $29,865,110 at the end of fiscal 2013 and $37,000,000 at the end of fiscal 2012. The Credit Facility with WFEC resulted in a loan discount being recorded. The discount was fully amortized over the original three-year term of the debt as additional interest expense, with $902,161 as an increase in additional paid-in-capital as a result of the revaluation of the WFEC warrants from $1.00 to $0.20 in fiscal 2013 as compared to $5,803,459 in fiscal 2012. There was no change in the capitalization of interest expense to the full cost pool for oil and gas properties during fiscal 2013 or 2012.
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Comparison of Fiscal 2012 to Fiscal 2011
OIL AND GAS SALES increased 13\% to $6,939,999 for fiscal 2012 from $6,133,299 for fiscal 2011 primarily due to increased gas volumes resulting from 19 Haynesville Shale wells being online for the entire fiscal year, of which eleven are operated by Chesapeake, three are operated by Goodrich and five are operated by EXCO. This increase was mitigated by the average price of natural gas being $3.07 per Mcfe for fiscal 2012, as compared to $4.10 per Mcfe for fiscal 2011.
Costs and Expenses
OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as "LEASE OPERATING EXPENSES" elsewhere herein) increased 6\% to $1,972,223 (28\% of oil and gas sales) for fiscal 2012 from $1,857,528 (30\% of oil and gas sales) for fiscal 2011. This increase was primarily due to a $135,741 increase in workover expenses on existing wells, which was necessitated by the age of the wells.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") increased 13\% to $3,572,260 for fiscal 2012 from $3,156,860 in fiscal 2011. This increase of $415,399 was primarily due to increased legal fees of $928,205 incurred primarily in the EXCO and BG arbitration. This increase was somewhat offset by a $286,052 decrease in stock compensation, a franchise tax decrease of $148,471, and overall decreased marketing expenses of $86,087.
DEPRECIATION, DEPLETION AND NON-LOAN RELATED AMORTIZATION ("DD&A") increased 64\% to $6,090,529 in fiscal 2012 from $3,707,255 in fiscal 2011, primarily due to an increase in the depletion percentage rate for fiscal 2012 of 6.27\% versus 2.53\% for fiscal 2011, which was primarily the result of an approximate 23.2 million Mcf reduction to our reserves. This reduction created a smaller full cost pool and increased the depletion rate accordingly. The depletion rate is a result of a change in beginning reserves, full cost pool to deplete, accumulated depletion and annual production.
INTEREST EXPENSE, INCLUDING AMORTIZATION OF LOAN DISCOUNT increased 1\% to $7,729,992 in fiscal 2012 from $7,648,622 in fiscal 2011; we had no increase in debt (before discounts), since August 2010 when it was increased $5,000,000 to a total outstanding balance of $37,000,000 for fiscal 2011 and all of fiscal 2012. The Credit Facility with WFEC also resulted in a loan discount being recorded. The discount is being amortized over the original three-year term of the debt as additional interest expense with $5,803,459 being recorded in fiscal 2012 as compared to $5,740,440 in fiscal 2011. There was no change in the capitalization of interest expense to the full cost pool for oil and gas properties of during fiscal 2012 as compared to a decrease of $5,221 in fiscal 2011.
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Liquidity and Capital Resources
The Company's primary resource is its oil and gas reserves. Our strategy with respect to our domestic exploration program seeks to maintain a balanced portfolio of drilling opportunities that range from lower risk, field extension wells to the smaller scale pursuit of Company appropriate higher risk, high reserve potential prospects.
Our recent acquisition of East Texas Basin assets is at the core of our current strategy, providing the lower risk development opportunities and high yield opportunities within the same property. The Company is exploring acquiring additional properties with this similar development profile.
Additionally, our focus is on exploration opportunities that can benefit from advanced technologies, including 3-D seismic, designed to reduce risks and increase success rates. We develop prospects in-house with an affiliate and through strategic alliances with exploration companies that have expertise in specific target areas. In addition, we evaluate externally generated prospects and look to participate in certain of these opportunities to enhance our portfolio.
We are currently focusing our domestic exploration activities to develop, re-enter, and re-complete existing well bores with respect to our recently acquired East Texas Basin assets; as well as developing our recently augmented leasehold interests in Louisiana. East Texas Basin prospects have been developed from the top of the Cretaceous formations all the way to the bottom of the Deep Bossier Shale. The various Cretaceous zones all have a strong oil and liquids component that will help the Company achieve its transition away from dry natural gas. The high production of dry natural gas from the various Bossier sands has the opportunity to provide the Company a significant increase in short term cash flow without substantial out-of-pocket expenditures, even at current commodity prices, through the re-recompletion and work over of existing wells. Prospects in our Louisiana leaseholds are focused on the Cotton Valley and the Haynesville Shale, but also include the Hosston; Gloyd; Pettet; Glen Rose and Paluxy.
Product prices, over which we have no control, have a significant impact on revenues from production and the value of such reserves and thereby on the Company's borrowing capacity. Within the confines of product pricing, the Company needs to be able to find and develop or acquire oil and gas reserves in a cost effective manner in order to generate sufficient financial resources through internal means to finance its capital expenditure program.
As a result of the acquisitions of properties from Gastar, the Company acquired proven reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas. The acquired properties include approximately 17,400 net acres of leasehold interests. The acquisition price paid by the Company at closing was $39,118,830, following various adjustments set forth in the Gastar Agreement, and net of the various deposits paid prior to the closing date. For purposes of allocating revenues and expenses and capital costs between Gastar and Cubic, such amounts were netted effective January 1, 2013 and will be recorded as an adjustment to the purchase price.
On September 27, 2013, the Company entered into the Navasota Agreement. On October 2, 2013, pursuant to the Navasota Agreement, the Company acquired proven reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas. The leasehold interests acquired from Navasota generally consist of additional fractional interests in the properties acquired pursuant to the Gastar Agreement, comprising approximately 6,400 net acres. The acquisition price paid by the Company was $19,400,000, prior to certain post-closing adjustments.
The Company entered into and consummated the Tauren Agreement dated as of October 2, 2013. Pursuant to the Tauren Agreement, the Company acquired well bores, proven reserves, oil & natural gas production and undeveloped leasehold interests in the Cotton Valley formation in De Soto and Caddo Parishes, Louisiana. The acquired properties include approximately 5,600 net acres of leasehold interests. The
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acquisition price paid by the Company was $4,000,000 in cash and 2,000 shares of the Company's Series B Convertible Preferred Stock with an aggregate stated value of $2,000,000.
Working Capital and Cash Flow
The Company had a working capital deficit of $30,191,399 at June 30, 2013, down from a working capital deficit of $35,768,341 at June 30, 2012. This decrease in deficit was primarily due to the $9,134,980 paydown on the Credit Agreement with WFEC with funds received from the proceeds of the EXCO/BG settlement.
The Company recently entered into a Note Purchase Agreement dated October 2, 2013, pursuant to which the Company issued an aggregate of $66,000,000 of senior secured notes due October 2, 2016, to certain purchasers. Pursuant to the terms of the Credit Agreement with WFEC, the Company repaid the $5 million term loan payable to WFEC, and Cubic Louisiana assumed the remaining unpaid debt to WFEC, which amount was $20,865,110 as of that date. That debt is reflected in a term loan bearing interest at the Wells Fargo Bank prime rate, plus 2\%, per annum. In the event that Cubic Louisiana does not have available cash to pay interest on the Credit Facility, accrued and unpaid interest will be paid in kind via an additional promissory note. As part of the Credit Agreement, WFEC is providing a revolving credit facility in the amount of up to $10,000,000, bearing interest at the same rate, with all advances under that revolving credit facility to be made in the sole discretion of WFEC. As part of the Recent Transactions, the Company entered into a Call Option Structured Derivative that provided the Company approximately $35,000,000 and together with the proceeds from the issuance of the senior secured notes, a total of $101,000,000. These funds, net of amounts paid for the acquisition of the assets from Gastar, Navasota and Tauren, the repayment of the term loan payable to WFEC and various expenses relating to the Recent Transactions, are available for capital expenditures and working capital for operations.
Mr. Wallen was issued 2,115 shares of Series B Convertible Preferred Stock, with an aggregate stated value of $2,115,000, in exchange for the cancellation of a promissory note payable to Mr. Wallen in the principal amount of $2,000,000, plus $114,986 of accrued and unpaid interest.
Operating activities - During the twelve months ended June 30, 2013, the Company generated cash flows from operating activities of $54,204 as compared to cash used of $395,058 in fiscal 2012 and $2,567,159 in fiscal 2011. Cash flow from operations is dependent on our ability to increase production through our development and exploratory activities and the price received for oil and natural gas.
Investing activities - During the twelve months ended June 30, 2013 the Company generated cash flows from investing activities of $7,325,735 as compared to cash used of $88,634 in fiscal 2012 and $1,412,406 in fiscal 2011. Cash provided by investing activities for 2013 consisted primarily of amounts received for the repayment of the remaining unused prepaid drilling credits required as part of the EXCO/BG settlement offset by deposits paid toward acquisitions and capital spending for the acquisition and development of oil and gas properties. Cash used in investing activities for 2012 and 2011consisted of capital spending for the acquisition and development of oil and gas properties.
Financing activities - During the twelve months ended June 30, 2013 the Company used cash flows from financing activities of $7,394,890 as compared to cash used of $783,029 in fiscal 2012 and cash provided of $5,129,915 in fiscal 2011. Cash used by financing activities for 2013 consisted primarily of payments on the credit facility and loan costs incurred offset by additional borrowing on a note payable to an affiliate. Cash used by financing activities for 2012 consisted of payment of dividends on preferred stock. Cash provided by financing activities for 201l consisted of borrowings under the credit facility and proceeds from the issuance of stock offset by dividends and loan costs paid.
The majority of our oil and gas reserves are undeveloped. As such, recovery of the Company's future undeveloped proved reserves will require significant capital expenditures. The Company recently raised
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$101,000,000 to consummate the Recent Transactions. The funds were provided through a Note Purchase Agreement totaling approximately $66,000,000 and a Call Option Structured Derivative of approximately $35,000,000. Management estimates that aggregate capital expenditures ranging from a minimum of approximately $15,000,000 and a maximum of approximately $35,000,000 will be made to further develop these reserves, closing fees, debt repayment and general operating fees during fiscal 2014. Moreover, additional capital expenditures may be required for exploratory drilling on our undeveloped acreage. The Company may increase its planned activities for fiscal 2014, if the Company acquires additional oil or natural gas properties. The Company has little or no control with respect to the timing of any third party operators drilling wells on acreage in which the Company has a working interest or the timing of drilling expenses incurred. Additional capital expenditures may be required for exploratory drilling on our undeveloped acreage.
No assurance can be given that all or any of these anticipated or possible capital expenditures will be completed as currently anticipated. Any acquisition of additional leaseholds would require that we obtain additional capital resources.
The Company plans to fund its development and exploratory activities through cash on hand, cash provided from operations, and recently secured funds in the Recent Transactions, a possible disposition of assets, if needed, or other transactions.
As future cash flows, the availability of borrowings, and the ability to consummate any of the aforementioned potential transactions are subject to a number of variables, such as prevailing prices of oil and gas, actual production from existing and newly-completed wells, the Company's success in developing and producing new reserves, the uncertainty of financial markets and joint venture and merger and acquisition activity, and the uncertainty with respect to the amount of funds which may ultimately be required to finance the Company's development and exploration program, there can be no assurance that the Company's capital resources will be sufficient to sustain the Company's development and exploratory activities. With future strategies to obtain additional financing, funds generated through existing wells and cash on hand, we expect to be able to continue to pay our expenses as they come due.
If we are unable to obtain sufficient capital resources on a timely basis, the Company may need to curtail its planned development and exploratory activities. If a well is proposed by a third-party operator and the Company does not have the capital resources to participate in that well, the Company might not receive any revenue generated by that well, while still being required to fulfill the relevant royalty payment obligations to the mineral owner and other royalty holders. Additionally, because future cash flows and the availability of borrowings are subject to a number of variables, there can be no assurance that the Company's capital resources will be sufficient to sustain the Company's development and exploration activities.
Critical Accounting Policies
In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we have identified the most critical accounting policies used in the preparation of our consolidated financial statements. We determined the critical policies by considering accounting policies that involve our most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our proved reserves, accounts receivables, share-based payments, our choice of accounting method for oil and natural gas properties, goodwill, asset retirement obligations and income taxes.
We prepared our consolidated financial statements for inclusion in this report in accordance with GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, and applying these rules and requirements requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP.
Table of Contents Estimates of Proved Reserves
The proved reserves data included in this Annual Report on Form 10-K was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:
† the quality and quantity of available data; † the interpretation of that data; † the accuracy of various mandated economic assumptions; and
† the technical qualifications, experience and judgment of the persons preparing the estimates.
Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. The assumptions used for our Bossier/Haynesville, Cotton Valley and Hosston well and reservoir characteristics and performance are subject to further refinement as more production history is accumulated.
You should not assume that the present value of future net cash flows represents the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves according to the requirements in the SEC's Release No. 33-8995 "Modernization of Oil and Gas Reporting," or Release No. 33-8995. Actual future prices and costs may be materially higher or lower than the prices and costs used in the preparation of the estimate. Further, the mandated discount rate of 10\% may not be an accurate assumption of future interest rates.
Proved reserves quantities directly and materially impact depletion expense. If the proved reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in the estimate of proved reserves may result from lower market prices, making it uneconomical to drill or produce if the costs to drill or produce are expected to exceed such market prices. In addition, a decline in proved reserves may impact the outcome of our assessment of our oil and natural gas properties and require an impairment of the carrying value of our oil and natural gas properties.
Proved reserves are defined as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimates are deterministic estimates or probabilistic estimates. To be classified as proved reserves, the project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.
The area of the reservoir considered as proved includes both the area identified by drilling, but limited by fluid contacts, if any, and adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the deepest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establish the deepest contact with reasonable certainty.
Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and the project has been approved for development by all necessary parties and entities, including governmental entities.
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Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Accounting for oil and natural gas properties
The accounting for and disclosure of, oil and natural gas producing activities requires that we choose between two GAAP alternatives: the full cost method or the successful efforts method.
We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the "full cost pool." Unproved property costs are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess possible impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries from drilling operations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus costs of acquired proved and unproved leaseholds.
During April 2004 we initiated leasing projects to acquire shale drilling rights in both the Johnson Branch and Bethany Longstreet fields in our Northeast Louisiana operating areas. In accordance with our policy and FASB ASC Subtopic 835-20 for Capitalization of Interest, we began capitalizing interest on unproved properties.
We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool and all estimated future development costs are divided by the total quantity of proved reserves. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation that is attributable to our acquisition, exploration, exploitation and development activities.
Under the full cost method of accounting, sales, dispositions and other oil and natural gas property retirements are generally accounted for as adjustments to the full cost pool, with no recognition of gain or loss unless the disposition would significantly alter the relationship between capitalized costs and proved reserves. Gain or loss recognition on divestiture or abandonment of oil and natural gas properties where disposition would result in a significant alteration of the depletion rate requires allocation of a portion of the amortizable full cost pool based on the relative estimated fair value of the disposed oil and natural gas properties to the estimated fair value of total proved reserves. As discussed under "Estimates of Proved Reserves," estimating oil and natural gas reserves involves numerous assumptions.
Prior to our December 31, 2009 adoption of Release No. 33-8995, at the end of each quarterly period the unamortized cost of oil and natural gas properties, net of related deferred income taxes, was limited to the full cost ceiling, computed as the sum of the estimated future net revenues from our proved reserves using period-end prices, discounted at 10\%, and adjusted for related income tax effects (ceiling test). In the event our capitalized costs exceeded the ceiling limitation at the end of the reporting period, we subsequently evaluated the limitation for price changes occurring after the balance sheet date to assess impairment. Beginning December 31, 2009, Release No. 33-8995 requires that the full cost ceiling be computed as the sum of the estimated future net revenues from proved reserves using the average, first-day-of-the-month price during the previous 12-month period, discounted at 10\% and adjusted for related income tax effects. The new rule no longer allows a company to subsequently evaluate the limitation for subsequent price changes. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods.
The quarterly calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality
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of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Use of estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Certain significant estimates
Management's estimates of oil and gas reserves are based on various assumptions, including constant oil and gas prices. It is reasonably possible that a future event in the near term could cause the estimates to change and such changes could have a severe impact. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. While it is at least reasonably possible that the estimates above will change materially in the near term, no estimate can be made of the range of possible changes that might occur.
Asset retirement obligations
We follow FASB ASC Subtopic 410-20 for Asset Retirement Obligations to account for legal obligations associated with the retirement of long-lived assets. ASC 410-20 requires these obligations be recognized at their estimated fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The costs of plugging and abandoning oil and natural gas properties fluctuate with costs associated with the industry. We periodically assess the estimated costs of our asset retirement obligations and adjust the liability according to these estimates.
Accounting for income taxes
Income taxes are accounted for using the liability method of accounting in accordance with FASB ASC Topic 740 for Income Taxes. We must make certain estimates related to the reversal of temporary differences, and actual results could vary from those estimates. Deferred taxes are recorded to reflect the tax benefits and consequences of future years' differences between the tax basis of assets and liabilities and their financial reporting basis. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized.
We account for share-based payments to employees using the methodology prescribed in FASB ASC Topic 718 for Stock Compensation. ASC Topic 718 requires share-based compensation to be recorded with cost classifications consistent with cash compensation.
The FASB issued new authoritative guidance for subsequent events. Such authoritative guidance establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, this statement sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and (3) the disclosures that an entity should make about events
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or transactions that occurred after the balance sheet date. Adoption of this authoritative position did not have a material impact on the Company's condensed consolidated financial statements.
Other Accounting Policies and Recent Accounting Pronouncements
In January 2013, the FASB issued ASU No. 2013-01- "Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities". The main objective in developing this update is to address implementation issues about the scope of ASU No. 2011-11. This ASU clarifies the scope of the offsetting disclosures and addresses any unintended consequences. The scope of Update 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. This ASU is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the required disclosures retrospectively for all comparative periods presented. This ASU was adopted on January 1, 2013 and the adoption did not have a material impact on our financial position or results of operations.
On January 21, 2010, the FASB issued Accounting Standards Update No. 2010-06-Fair Value Measurement and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires transfers, and the reasons for the transfers, between Levels 1 and 2 be disclosed, Level 3 reconciliations for fair value measurements using significant unobservable inputs should be presented on a gross basis, the fair value measurement disclosure should be reported for each class of asset and liability, and disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring transactions will be required for fair value measurements that fall in either Level 2 or 3. The update was effective for interim and annual reporting periods beginning after December 15, 2009. This update currently has had no impact to our financial position.
On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. On January 16, 2010, the FASB issued Update No. 2010-03-Extractive Activities-Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures, or Update No. 2010-03, to align the oil and gas reserve estimation and disclosure requirements of the Codification with Release No. 33-8995.
The effective date of the new accounting and disclosure requirements was for annual reports filed for fiscal years ending on or after December 31, 2009.
Among other things, Release No. 33-8995 and Update No. 2010-03:
† Revises a number of definitions relating to oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves;
† Permits the use of new technologies for determining oil and natural gas reserves;
† Requires the use of the simple average spot prices for the trailing twelve month period using the first day of each month in the estimation of oil and natural gas reserve quantities and, for companies using the full cost method of accounting, in computing the ceiling limitation test, in place of a single day price as of the end of the fiscal year;
† Permits the disclosure in filings with the SEC of probable and possible reserves and sensitivity of our proved oil and natural gas reserves to changes in prices;
† Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period; and
† Requires a discussion of the internal controls in place in the reserve estimation process and disclosure of the technical qualifications of the technical person having primary responsibility for preparing the reserve estimates.
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Other Accounting Policies and Recent Accounting Pronouncements
Please see "Notes to Financial Statements - Note B - Significant accounting policies" elsewhere herein.
Although the level of inflation affects certain of the Company's costs and expenses, inflation did not have a significant effect on the Company's results of operations during fiscal 2013.
Related Party Transactions
A description of our related party transactions is included in "Note F - Related party transactions" in the Notes to the Financial Statements of the Company included elsewhere in this Report, and is incorporated herein by reference.
Off-Balance Sheet Arrangements
We do not currently use any off-balance sheet arrangements to enhance our liquidity and capital resource positions, or for any other purpose.
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