SAXON CAPITAL GROUP INC 10-Q

Item 2. Management’s Discussion Analysis of Financial Condition and Results of Operations The following discussion will assist you in understanding our financial position, liquidity, and results of operations. The information below should be read in conjunction with the consolidated financial statements, and the related notes to consolidated financial statements. Our discussion contains both historical and forward-looking information. We assess the risks and uncertainties about our business, long-term strategy, and financial condition before we make any forward-looking statements, but we cannot guarantee that our assessment is accurate or that our goals and projections can or will be met. Statements concerning results of future exploration, exploitation, development, and acquisition expenditures as well as expense and reserve levels are forward-looking statements. We make assumptions about commodity prices, drilling results, production costs, administrative expenses, and interest costs that we believe are reasonable based on currently available information. Critical Estimates and Accounting Policies We prepare our consolidated financial statements in this report using accounting principles that are generally accepted in the United States (“GAAP”). GAAP represents a comprehensive set of accounting and disclosure rules and requirements. We must make judgments, estimates, and in certain circumstances, choices between acceptable GAAP alternatives as we apply these rules and requirements, which may affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. The most critical estimate we use is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the full cost method of accounting, the calculation of depreciation and depletion of oil and gas properties and the estimate of the impairment of our oil and gas properties. It also affects the estimated lives of our assets used to determine asset retirement obligations. Full Cost Method Accounting We use the full cost method of accounting for oil and gas producing activities. Our costs incurred in connection with the acquisition, exploration for and development of petroleum and natural gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on non-producing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. Sales of Oil and Gas Properties Proceeds from the sale of properties are applied against capitalized costs, without any gain or loss being recognized, unless such a sale would significantly alter the rate of depletion and depreciation. Depreciation and Depletion of Oil and Gas Properties Depletion of exploration and development costs and depreciation of production equipment is provided using the unit-of-production method based upon estimated proven oil and gas reserves. The costs of significant unevaluated properties are excluded from costs subject to depletion. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the equivalent conversion based upon relative energy content. Ceiling Test In applying the full cost method, we perform an annual ceiling test whereby the carrying value of oil and gas properties and production equipment, net of recorded future income taxes and the accumulated provision for site restoration and abandonment costs, is compared annually to an estimate of future net cash flow from the production of proven reserves. Costs related to undeveloped oil and gas properties are excluded from the ceiling tests. Discounted net cash flow, utilizing a 10% discount rate, is estimated using year end prices, less estimated future general and administrative expenses, financing costs and income taxes. Should this comparison indicate an excess carrying value, the excess is charged against earnings. For the years ended December 31, 2007 and 2006, no impairment of oil and gas properties was indicated. Asset Retirement Obligations We record a liability for legal obligations associated with the retirement of tangible long-lived assets in the period in which they are incurred in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations.” Under this method, when liabilities for dismantlement and abandonment costs (ARO) are initially recorded, the carrying amount of the related oil and natural gas properties are increased. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset. Revisions to such estimates are recorded as adjustments to the ARO, capitalized asset retirement costs and charges to operations during the periods in which they become known. At the time the abandonment cost is incurred, we will be required to recognize a gain or loss if the actual costs do not equal the estimated costs included in ARO. Concentrations of Credit Risk We sold all of our oil and natural gas production to two customers in 2007. We maintain our cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $100,000. At March 31, 2007 all of our cash deposits were within FDIC insured limits. We have not experienced any losses in such accounts. Revenue and Cost Recognition We use the sales method to account for sales of crude oil and natural gas. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. The volumes sold may differ from the volumes to which we are entitled based on our interest in the properties. These differences create imbalances which are recognized as a liability only when the imbalance exceeds the estimate of remaining reserves. We had no imbalances as of December 31, 2007 and March 31, 2008. Costs associated with production are expensed in the period incurred. Cash and cash equivalents Cash and cash equivalents include cash in banks and liquid deposit with maturities of three months or less. Fair Value of Financial Instruments The carrying value of cash and cash equivalents, accounts payable and accrued expenses and other liabilities approximates fair value due to the short term maturity of these instruments. The carrying value of the notes payable, convertible notes and convertible debentures approximate their fair value as December 31, 2007 and 2006. Property and Equipment Property and equipment are stated at cost. Depreciation is computed on a straight-line basis over the estimated useful lives of three to five years. Stock-based compensation On January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment”. SFAS 123(R) replaced SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123(R) requires all stock-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. Loss per share Basic net loss per common share is computed by dividing net loss by the weighted-average number of common shares outstanding during the period. Diluted net loss per common share is determined using the weighted-average number of common shares outstanding during the period, adjusted for the dilutive effect of common stock equivalents. In periods when losses are reported, the weighted-average number of common shares outstanding excludes common stock equivalents, because their inclusion would be anti-dilutive. Standardized measure of discounted future net cash flows The standardized measure of discounted future net cash flows relies on these estimates of oil and gas reserves using commodity prices and costs which existed at year-end. In our 2007 year-end reserve report, we used the December 31, 2007 WTI Cushing spot price of $96.01 per Bbl and Henry Hub spot natural gas price of $7.465 per MMbtu, adjusted by property for energy content, quality, transportation fees, and regional price differentials. The weighted average price over the lives of the properties was $88.45 per Bbl for oil and $6.00 per Mcf for gas. While we believe that future operating costs can be reasonably estimated, future prices are difficult to estimate since market prices are influenced by events beyond our control. Future global economic and political events will most likely result in significant fluctuations in future oil prices, while future U.S. natural gas prices will continue to be influenced by primarily domestic market factors, including supply and demand, weather patterns and public policy. Income taxes Income taxes are accounted for using the asset/liability method of income tax allocation. Future income taxes are recognized for the future income tax consequences attributable to differences between the carrying values of assets and liabilities and their respective income tax bases. Future income tax assets and liabilities are measured using income tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on future income tax assets and liabilities of a change in income tax rates is included in earnings in the period that such change in income tax rates is enacted. Future income tax assets are recorded in the financial statements if realization is considered more likely than not. Business Strategy USA Superior Energy Holdings, Inc. (the “Company”) is focused on acquiring, owning, operating and applying enhanced oil recovery (“EOR”) techniques to existing shallow fields of oil and gas. The Company performs complete workover and stimulation services in these existing fields to restart or substantially increase production. It utilizes state-of-the-art workover and shallow-well drilling techniques in these fields including new and innovative technologies under development by the Company. These new technologies include specialized shallow-well cased hole horizontal drilling (“CHHD”) and nitrogen (“N2”) injection which will be utilized to increase production volumes and reserve recoverability from the Company’s projects. Currently, the Company is involved in developing, owning and operating energy projects and prospects in East, Central and South Texas and currently has active projects and prospects in Bastrop, Caldwell, Navarro and Zavalla counties. These fields are known as the Bateman Project in Bastrop and Caldwell Counties (comprised of the Bateman Field and part of the adjacent Dale McBride Field), the Benton Field in Navarro County and the Del Monte Prospect in Zavalla County. Going Concern The report of our independent registered public accounting firm on the financial statements for the year ended December 31, 2007, includes an explanatory paragraph indicating substantial doubt as to our ability to continue as a going concern. We incurred a net loss of $553,402 for the quarter ended March 31, 2008 and have a working capital deficit of $777,368 at March 31, 2008, excluding prepaid expenses relating primarily to services paid for with common stock. We require significant additional funding to sustain our operations and satisfy our contractual obligations for our planned oil and gas exploration and development operations. Our ability to establish the Company as a going concern is dependent upon our ability to obtain additional financing, in order to fund our planned operations and ultimately, to achieve profitable operations. Liquidity and Capital Resources Our main sources of liquidity and capital resources for the quarter ended March 31, 2008 were cash flows from operations and draw down of our cash balances. During the quarter, we entered into a financing arrangement with our oil purchasing customers which allows for immediate payment on barrels delivered. While this may reduce the price we might otherwise receive for our production, we have been able to accelerate cash flow from revenues to enhance or liquidity by receiving cash upon the delivery of our barrels. During the quarter ended March 31, 2008, net cash flow used by operating activities increased by $[541,000] to $[687,000], as compared to $[146,000] for our [2006 fiscal year], primarily because of our increased operating and general and administrative expenses only partially offset by increased revenues received during the year. We expect our cash flow provided by operations to continue to increase during 2008, mainly due to increased oil and natural production resulting from our existing properties. The Bastrop and Caldwell County properties were acquired in 2007 and were shut in for a portion of that year. We expect to receive a full year of revenue from these wells in 2008. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production rates and in commodity prices. In addition, our oil and gas production from either of our properties may be curtailed due to weather-related factors beyond our control. In addition, maintenance activities on, or damage to, major pipelines or processing facilities can also cause us to shut-in production for undetermined lengths of time. Our realized oil and gas prices vary significantly due to world political events, supply and demand for products, product storage levels, and weather patterns, among other factors. We sell 100% of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. We incurred capital expenditures totaling approximately $[442,000] during the quarter ended March 31, 2008. The capital expenditures primarily related to capitalizable costs associated with the Bateman Project. We anticipate making additional capital expenditures of approximately $4,000,000 over the next several years to drill additional wells on our existing properties. The remainder of our 2008 capital budget will be funded from a combination of our cash flow from operations, our cash and cash equivalents and the proceeds from offerings of debt and/or equity securities. The required principal payments on our notes and debentures are as follows as of December 31, 2007: 2008 $ 618,000 2009 $ 237,000 2010 $ 558,000 2011 $ 37,000 $ 1,450,000 Changes in our working capital accounts from 2007 to 2008 include an increase in Accounts payable and accrued liabilities by $[169,000] to $[327,000] at March 31, 2008 due to the increase in operating activities. Current notes payable increased to $372,403 from a $347,762 at December 31, 2007 due to accrual on our various borrowings. On March 31, 2008, our current liabilities exceeded our current assets by $777,368, excluding prepaid expenses relating primarily to services paid for with common stock. While we expect to achieve positive cash flow from operations during 2008, we will require additional funding in order to complete our plans to develop additional wells on existing properties. Results of Operations Revenue We produced [3,854] barrels of oil and recognized revenue of $115,563 during the quarter ended March 31, 2008, an increase of _____ barrels and $100,120 over 2007, primarily because we had a full quarter of production from the Bateman Project which was acquired in late in the first quarter of 2007 and because we realized significantly higher prices for our production. Lease operating expense and production taxes Our production costs totaled $89,495 during the quarter ended March 31, 2008, an increase of $70,732 over 2007, primarily because we had a full quarter of production from the Bateman Project which was acquired in late in the first quarter of 2007. Accretion of asset retirement obligation Accretion expense for the quarter ended March 31, 2008 was $[8,000], as compared to $[1,000] for same quarter in 2007. This reflects our acquisition of the Bastrop and Caldwell County properties during the first quarter of 2007. Depletion, depreciation and amortization (DD&A) For our quarter ended March 31, 2008, we recorded DD&A expense of $21,243, after having recorded only $1,069 of DD&A expense during the first quarter of 2007. Virtually all of this expense was attributable to depletion of our oil and gas properties, which were acquired during the first quarter of 2007. General and administrative expense (G&A expense) General and administrative expense for the quarter ended March, 31 2008 decreased $2,858,580 from the comparable 2007 period to $516,505. The largest portion of the reduction came from a decrease in stock based compensation of $[5,680,000] from the same period in 2007 which related to the reverse merger and compensation of key employees and consultants. The other major component of general and administrative costs for the quarter ended March 31, 2008 included salaries of $[361,000]. Other income (expense) Other income (expense) for the quarter ended March 31, 2008 was incurred interest expense of $41,722 during the quarter. We incurred no interest expense during the same quarter in 2007 because the acquisition of the Bateman project and related financing occurred at the end of the first quarter of 2007. Net loss For the quarter ended March 31, 2008, our net loss decreased to $553,402, compared to our same quarter 2007 net loss of $3,379,474. The major components of the first quarter 2008 loss were general and administrative expenses of $516,505 including stock based compensation of $[5,680,000]. New Accounting Pronouncements USA Superior does not expect the adoption of recently issued accounting pronouncements to have a significant impact on their results of operations, financial position or cash flows Item 3. Quantitative and Qualitative Disclosures About Market Risk