The following is management’s discussion and analysis of certain significant factors that have affected certain aspects of the Company’s financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2006 and the unaudited financial statements included elsewhere herein.
Our third quarter 2007 included revenues of $30.3 million and record production of 4.4 Bcfe. The key drivers to our success for the three and nine-month periods ended September 30, 2007 include the following:
Oil and natural gas revenues for the three months ended September 30, 2007 increased to $30.3 million from $20.3 million for the same period in 2006. Production volumes for natural gas for the three months ended September 30, 2007 increased to 4.1 Bcf from 2.4 Bcf for the same period in 2006. Average natural gas prices, excluding the impact of the gain from our cash settled derivatives of $2.8 million and $1.1 million for the quarters ended September 30, 2007 and 2006, respectively, decreased to $6.33 per Mcf in the third quarter of 2007 from $6.39 per Mcf in the same period in 2006. Average oil prices for the quarter ended September 30, 2007 increased 10% to $75.40 from $68.46 per barrel in the same period in 2006. The increase in natural gas production volume was due primarily to the addition of new Barnett Shale wells, production from the Baby Ruth and Doberman #1 wells in the Gulf Coast region and increased production from the recompleted Galloway Gas Unit 1 well #1 and LL&E #1 in the Gulf Coast area.
The following table summarizes production volumes, average sales prices and operating revenues (excluding the impact of derivatives) for the three months ended September 30, 2007 and 2006:
| | | | | | | | | 2007 Period | |
| | | Three Months Ended | | | Compared to 2006 Period | |
| | | September 30, | | | Increase | | | % Increase | |
| | | 2007 | | | 2006 | | | (Decrease) | | | (Decrease) | |
| Production volumes | | | | | | | | | | | | |
| Oil and condensate (MBbls) | | | 59 | | | | 69 | | | | (10 | ) | | | (14 | )% |
| Natural gas (MMcf) | | | 4,080 | | | | 2,443 | | | | 1,637 | | | | 67 | % |
| Average sales prices | | | | | | | | | | | | | | | | |
| Oil and condensate (per Bbl) | | $ | 75.40 | | | $ | 68.46 | | | $ | 6.94 | | | | 10 | % |
| Natural gas (per Mcf) | | | 6.33 | | | | 6.39 | | | | (0.06 | ) | | | (1 | )% |
| Operating revenues (In thousands) | | | | | | | | | | | | | |
| Oil and condensate | | $ | 4,457 | | | $ | 4,716 | | | $ | (259 | ) | | | (5 | )% |
| Natural gas | | | 25,848 | | | | 15,617 | | | | 10,231 | | | | 66 | % |
| | | | | | | | | | | | | | | | | |
| Total Operating Revenues | | $ | 30,305 | | | $ | 20,333 | | | $ | 9,972 | | | | 49 | % |
| | | | | | | | | | | | | | | | | |
Oil and natural gas operating expenses for the three months ended September 30, 2007 increased 78% to $6.9 million from $3.9 million for the same period in 2006 primarily as a result of (1) higher lifting costs of $0.9 million primarily attributable to increased production and the increased number of producing wells, (2) increased workover expense of $0.3 million, (3) increased ad valorem taxes of $0.4 million and (4) increased transportation and other product costs of $1.3 million mainly attributable to the Barnett Shale area.
Depreciation, depletion and amortization (DD&A) expense for the three months ended September 30, 2007 increased 34% to $10.2 million ($2.30 per Mcfe) from $7.6 million ($2.66 per Mcfe) for the same period in 2006. This increase was primarily due to an increase in production volumes partially offset by a decrease in the DD&A rate attributable to the increase in the reserve base.
General and administrative expense for the three months ended September 30, 2007 increased by $1.3 million to $4.4 million from $3.1 million for the corresponding period in 2006 primarily as a result of (1) an increase in staff and related costs, (2) increased stock-based compensation, (3) increased legal and consulting fees and (4) higher rent expense as a result of office expansion.
The net gain on derivatives of $3.7 million in the third quarter of 2007 was comprised of (1) $2.8 million of realized gain on net cash settled derivatives and (2) $0.9 million of net unrealized mark-to-market gain on derivatives. The net gain on derivatives of $3.7 million in the third quarter of 2006 was comprised of (1) $1.5 million of realized gain on net cash settled derivatives and (2) $2.2 million of net unrealized mark-to-market gain on derivatives.
Interest expense and capitalized interest for the three months ended September 30, 2007 were $7.0 million and ($2.9) million, respectively, as compared to $4.9 million and $(2.7) million for the same period in 2006. The increases in 2007 were largely attributable to the $75.0 million increase in our Second Lien Credit Facility in January 2007, the borrowings under the Senior Secured Credit Facility and higher effective interest rates.
Income tax expense increased to $3.1 million for the three months ended September 30, 2007 from the $2.7 million expense for the same period in 2006 as a result of higher taxable income.
Nine Months Ended September 30, 2007,
Compared to the Nine Months Ended September 30, 2006
Oil and natural gas revenues for the nine months ended September 30, 2007 increased 46% to $85.8 million from $58.7 million for the same period in 2006. Production volumes for natural gas for the nine months ended September 30, 2007 increased to 10.8 Bcf from 7.0 Bcf for the same period in 2006. Average natural gas prices excluding the impact of the gain from our cash settled derivatives of $5.4 million and $3.6 million for the nine months ended September 30, 2007 and 2006, respectively, increased 2% to $6.88 per Mcf from $6.74 per Mcf in the same period in 2006. Average oil prices for the nine months ended September 30, 2007 decreased 1% to $65.22 from $65.54 per barrel in the same period in 2006. The increase in natural gas production volume was due primarily to new
Barnett Shale wells and increased production in the Gulf Coast from the addition of the Doberman #1 and Baby Ruth wells and the recompletion of the Galloway Gas Unit #1 well #1.
The following table summarizes production volumes, average sales prices and operating revenues (excluding the impact of derivatives) for the nine months ended September 30, 2007 and 2006:
| | | | | | | | | 2007 Period | |
| | | Nine Months Ended | | | Compared to 2006 Period | |
| | | September 30, | | | Increase | | | % Increase | |
| | | 2007 | | | 2006 | | | (Decrease) | | | (Decrease) | |
| Production volumes | | | | | | | | | | | | |
| Oil and condensate (MBbls) | | | 182 | | | | 179 | | | | 3 | | | | 2 | % |
| Natural gas (MMcf) | | | 10,753 | | | | 6,976 | | | | 3,777 | | | | 54 | % |
| Average sales prices | | | | | | | | | | | | | | | | |
| Oil and condensate (per Bbl) | | $ | 65.22 | | | $ | 65.54 | | | $ | (0.32 | ) | | | (1 | )% |
| Natural gas (per Mcf) | | | 6.88 | | | | 6.74 | | | | 0.14 | | | | 2 | % |
| Operating revenues (In thousands) | | | | | | | | | | | | | |
| Oil and condensate | | $ | 11,881 | | | $ | 11,734 | | | $ | 147 | | | | 1 | % |
| Natural gas | | | 73,927 | | | | 46,993 | | | | 26,934 | | | | 57 | % |
| | | | | | | | | | | | | | | | | |
| Total Operating Revenues | | $ | 85,808 | | | $ | 58,727 | | | $ | 27,081 | | | | 46 | % |
| | | | | | | | | | | | | | | | | |
Oil and natural gas operating expenses for the nine months ended September 30, 2007 increased 56% to $17.2 million from $11.0 million for the same period in 2006 primarily as a result of (1) higher lifting costs of $2.5 million primarily attributable to increased production, the increased number of producing wells and the rising costs of oilfield services, (2) higher workover expenses of $0.4 million, (3) increased ad valorem taxes of $0.9 million and (4) increased transportation and other product costs of $2.3 million mainly attributable to the Barnett Shale area.
DD&A expense for the nine months ended September 30, 2007 increased 34% to $29.0 million ($2.45 per Mcfe) from $21.6 million ($2.69 per Mcfe) for the same period in 2006. This increase was primarily due to an increase in production volumes partially offset by a decrease in the DD&A rate attributable to the increase in the reserve base.
General and administrative expense for the nine months ended September 30, 2007 increased by $3.1 million to $13.6 million from $10.5 million for the corresponding period in 2006 due primarily to (1) an increase in staff and related costs, (2) increased stock-based compensation, (3) higher rent and office expense due to office expansion and (4) increased legal and consulting fees.
The net gain on derivatives of $2.1 million in the first nine months of 2007 was comprised of (1) $5.6 million of realized gain on net cash settled derivatives and (2) $(3.5) million of net unrealized mark-to-market loss on derivatives. The net gain on derivatives of $12.1 million in the first nine months of 2006 was comprised of (1) $4.3 million of realized gain on net cash settled derivatives and (2) $7.8 million of net unrealized mark-to-market gain on derivatives.
Interest expense and capitalized interest for the nine months ended September 30, 2007 were $19.7 million and $(8.3) million, respectively, as compared to $13.8 million and $(7.2) million for the same period in 2006. The increases in 2007 were largely attributable to the $75.0 million increase in our Second Lien Credit Facility in January 2007, borrowings under the Senior Secured Credit Facility beginning mid-2006 and higher effective interest rates.
Income tax expense decreased to $6.3 million for the nine months ended September 30, 2007 from the $7.8 million for the same period in 2006 as a result of lower taxable income.
Liquidity and Capital Resources
Sources and Uses of Cash. During the nine months ended September 30, 2007, capital expenditures, net of proceeds for property sales, exceeded our net cash. During 2007, we have used cash generated from operations, additional borrowings under our Second Lien Credit Facility and the Senior Credit Facility and proceeds from the issuance of our common stock. Potential primary sources of future liquidity include the following:
| · | Cash on hand and cash generated by operations. Cash flows from operations are highly dependent on commodity prices and market conditions for oil and gas field services. We hedge a portion of our production to reduce the downside risk of declining natural gas prices. |
| · | Available draws on the Senior Credit Facility. During the third quarter of 2007, we requested a borrowing base re-determination for the Senior Credit Facility and in September of 2007, the borrowing base availability increased from $74.8 million to $117.0 million. At November 1, 2007, cash available under the Senior Credit Facility was $105.0 million. The next borrowing base redetermination is scheduled for December 2007. |
| · | Other debt and equity offerings. As situations or conditions arise, we may issue debt or equity instruments to supplement our cash flows. |
| · | Asset sales. In order to fund our drilling program, we may consider the sale of certain properties or assets no longer deemed core to our future growth. |
Our primary use of cash is capital expenditures related to our drilling program. We plan to spend approximately $145 million to $165 million on our 2007 drilling program. For the nine months ended September 30, 2007, we have incurred approximately $151 million in capital expenditures.
Overview of Cash Flow Activities. Cash flows provided by operating activities were $49.5 million and $37.2 million for the nine months ended September 30, 2007 and 2006, respectively. The increase was primarily due to an increase in income largely attributable to increased production.
Cash flows used in investing activities were $152.2 million for the nine months ended September 30, 2007 and related primarily to oil and gas property expenditures. Cash flows used in investing activities were $114.9 million for the nine months ended September 30, 2006 as capital expenditures for oil and gas properties of $146.2 million were partially offset by proceeds from the sale of properties of $33.6 million.
Net cash provided by financing activities for the nine months ended September 30, 2007 was $101.9 million and related primarily to the additional borrowings of $75.0 million under the Second Lien Credit Facility in January 2007 and net proceeds of $72.0 million from the issuance of common stock in September 2007 (see Notes 2 and 6 in the Notes to Consolidated Financial Statements for further discussion of these transactions). These cash proceeds were partially offset by the paydown of the Senior Credit Facility. Net cash provided by financing activities for the nine months ended September 30, 2006 was $50.3 million and related primarily to the additional borrowings under the Senior Credit Facility and the net proceeds of $33.6 million from the issuance of common stock, partially offset by $36.2 million of debt repayments.
Liquidity/Cash Flow Outlook. We believe that the cash generated from operations along with cash on hand and the cash available under the Senior Credit Facility is sufficient to meet our immediate needs but we may need to seek other financing alternatives, including additional debt or equity financings, to fully fund our 2007 and 2008 capital program, especially if there are additional capital needs in our Floyd Shale or North Sea plays.
We may not be able to obtain financing needed in the future on terms that would be acceptable to us. If we cannot obtain adequate financing, we may be required to limit or defer our planned oil and natural gas exploration and development program, thereby adversely affecting the recoverability and ultimate value of our oil and natural gas properties.
Contractual Obligations
During the third quarter of 2007, we entered into a firm drilling agreement for one rig over a three-year term scheduled to begin in the first quarter of 2008. The estimated obligation is approximately $8 million per year through 2010.
Financing Arrangements
Senior Secured Revolving Credit Facility
During the third quarter of 2007, we amended our Senior Credit Facility as discussed in Note 2 in the Notes to Consolidated Financial Statements.
Effects of Inflation and Changes in Price
Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that we are required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on us.
Recently Adopted Accounting Pronouncements
We adopted the Financial Accounting Standards Board's Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109” (“FIN 48”), effective January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in financial statements and requires the impact of a tax position to be recognized in the financial statements if that position is more likely than not of being sustained by the taxing authority. The adoption of FIN 48 did not have a material effect on our consolidated financial position or results of operations.
Critical Accounting Policies
The following summarizes several of our critical accounting policies:
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that 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 amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates. The use of these estimates significantly affects our natural gas and oil properties through depletion and the full cost ceiling test, as discussed in more detail below.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, the collectability of outstanding accounts receivable, fair values of derivatives, stock-based compensation expense, contingencies and the results of current and future litigation. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling, testing and production may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
The significant estimates are based on current assumptions that may be materially effected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the market value of our common stock and corresponding volatility and our ability to generate future taxable income. Future changes to these assumptions may materially affect these significant estimates in the near term.
Oil and Natural Gas Properties
We account for investments in natural gas and oil properties using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of natural gas and oil properties are capitalized. These costs include lease acquisitions, seismic surveys, and drilling and completion equipment. We proportionally consolidate our interests in natural gas and oil properties. We capitalized compensation costs for employees working directly on exploration activities of $3.3 million and $2.2 million for the nine months ended September 30, 2007 and 2006, respectively. We expense maintenance and repairs as they are incurred.
We amortize natural gas and oil properties based on the unit-of-production method using estimates of proved reserve quantities. We do not amortize investments in unproved properties until proved reserves associated with the projects can be determined or until these investments are impaired. We periodically evaluate, on a property-by-property basis, unevaluated properties for impairment. If the results of an assessment indicate that the properties are impaired, we add the amount of impairment to the proved natural gas and oil property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per Mcfe for the three months ended September 30, 2007 and 2006 was $2.26 and $2.59, respectively.
We account for dispositions of natural gas and oil properties as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. We have not had any transactions that significantly alter that relationship.
Net capitalized costs of proved oil and natural gas properties are limited to a “ceiling test” based on the estimated future net revenues, discounted at 10% per annum, from proved oil and natural gas reserves based on current economic and operating conditions (“Full Cost Ceiling”). If net capitalized costs exceed this limit, the excess is charged to earnings through depreciation, depletion and amortization.
In connection with our September 30, 2007 Full Cost Ceiling test computation, a price sensitivity study also indicated that a 10% increase or decrease in commodity prices at September 30, 2007 would have increased or decreased the Full Cost Ceiling test cushion by approximately $52 million. The aforementioned price sensitivity is as of September 30, 2007 and, accordingly, does not include any potential changes in reserve values due to subsequent performance or events, such as commodity prices, reserve revisions and drilling results.
The Full Cost Ceiling cushion at the end of September 2007 of approximately $113.7 million was based upon average realized oil and natural gas prices of $76.79 per Bbl and $6.48 per Mcf, respectively, or a volume weighted average price of $45.63 per BOE. This cushion, however, would have been zero on such date at an estimated volume weighted average price of $35.61 per BOE. A BOE means one barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher, more often for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.
Under the full cost method of accounting, the depletion rate is the current period production as a percentage of the total proved reserves. Total proved reserves include both proved developed and proved undeveloped reserves. The depletion rate is applied to the net book value of our oil and natural gas properties, excluding unevaluated costs, plus estimated future development costs and salvage value, to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.
We have a significant amount of proved undeveloped reserves. We had 116.9 Bcfe and 126.2 Bcfe of proved undeveloped reserves at September 30, 2007 and December 31, 2006, respectively, representing 48% and 60% of our total proved reserves. As of September 30, 2007 and December 31, 2006, a large portion of these proved undeveloped reserves, or approximately 32.8 Bcfe, are attributable to our Camp Hill properties that we acquired in 1994. The estimated future development costs to develop our proved undeveloped reserves on our Camp Hill properties are relatively low, on a per Mcfe basis, when compared to the estimated future development costs to develop our proved undeveloped reserves on our other oil and natural gas properties. Furthermore, the average depletable life (the estimated time that it will take to produce all recoverable reserves) of our Camp Hill properties is considerably longer, or approximately 15 years, when compared to the depletable life of our remaining oil and natural gas properties of approximately 10 years. Accordingly, the combination of a relatively low ratio of future development costs and a relatively long depletable life on our Camp Hill properties has resulted in a relatively low overall historical depletion rate and DD&A expense. This has resulted in a capitalized cost basis associated with producing properties being depleted over a longer period than the associated production and revenue stream, causing the build-up of nondepleted capitalized costs associated with properties that have been completely depleted. This combination of factors, in turn, has had a favorable impact on our earnings, which have been higher than they would have been had the Camp Hill properties not resulted in a relatively low overall depletion rate and DD&A expense and longer depletion period. As a hypothetical illustration of this impact, the removal of our Camp Hill proved undeveloped reserves starting January 1, 2002 would have reduced our earnings by (1) an estimated $11.2 million in 2002 (comprised of after-tax charges for a $7.1 million full cost ceiling impairment and a $4.1 million depletion expense increase), (2) an estimated $5.9 million in 2003 (due to higher depletion expense), (3) an estimated $3.4 million in 2004 (due to higher depletion expense) (4) an estimated $6.9 million in 2005 (due to higher depletion expense) and (5) an estimated $0.7 million in 2006 (due to higher depletion expense).
We expect our relatively low historical depletion rate to continue until the high level of nonproducing reserves to total proved reserves is reduced and the life of our proved developed reserves is extended through development drilling and/or the significant addition of new proved producing reserves through acquisition or exploration. If our level of total proved reserves, finding costs and current prices were all to remain constant, this continued build-up of capitalized cost increases the probability of a ceiling test write-down in the future.
We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to ten years.
Oil and Natural Gas Reserve Estimates
Proved reserve data as of December 31, 2006 were estimates prepared by Ryder Scott Company, LaRoche Petroleum Consultants, Ltd., and Fairchild & Wells, Inc., Independent Petroleum Engineers. We estimated the reserve data for all other dates. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on judgment and the interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The SEC mandates some of these assumptions such as oil and natural gas prices and the present value discount rate.
Proved reserve estimates prepared by others may be substantially higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates may be made depending on the results of drilling, testing, and rates of production.
You should not assume that the present value of future net cash flows is 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 on prices and costs on the date of the estimate using a discount rate of 10%.
Our rate of recording depreciation, depletion and amortization expense for proved properties depends on our estimate of proved reserves. If these reserve estimates decline, the rate at which we record these expenses will increase. A 10% increase or decrease in our proved reserves would have increased or decreased our depletion expense by 9% for the three months ended September 30, 2007.
At December 31, 2006, approximately 75% of our proved reserves were proved undeveloped and proved nonproducing. Moreover, some of the producing wells included in our reserve reports as of December 31, 2006 had produced for a relatively short period of time as of that date. Because most of our reserve estimates are calculated using volumetric analysis, those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on seismic analysis. In addition, realization or recognition of our proved undeveloped reserves will depend on our development schedule and plans. Lack of certainty with respect to development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved. We have from time to time chosen to delay development of our proved undeveloped reserves in the Camp Hill field in East Texas in favor of pursuing shorter-term exploration projects with higher potential rates of return, adding to our lease position in this field and further evaluating additional economic enhancements for this field's development. The average life of the Camp Hill proved undeveloped reserves is approximately 15 years, with 50% of these reserves being booked over eight years ago. Although we have increased the pace of the development of the Camp Hill project, there can be no assurance that the aforementioned discontinuance will not occur. For more information on the development of the Camp Hill field, see “Outlook” above.
Derivative Instruments
We use derivatives to manage price and interest rate risk underlying our oil and natural gas production and the variable interest rate on the Second Lien Credit Facility. We have elected to account for our derivative contracts as non-designated derivatives that will be marked-to-market. For a discussion of the impact of changes in the prices of oil and gas on our hedging transactions, see “Volatility of Oil and Natural Gas Prices” below.
During 2007, we entered into interest rate swap agreements with respect to amounts outstanding under the amended Second Lien Credit Facility. These arrangements are designed to manage our exposure to interest rate fluctuations through December 31, 2008 by effectively exchanging existing obligations to pay interest based on floating rates for obligations to pay interest based on fixed LIBOR. These derivatives will be marked-to-market at the end of each period and the realized and unrealized gain or loss will be recorded as gain (loss) on derivatives, net within Other Income and Expenses on our Consolidated Statements of Income.
Our Board of Directors sets all of our risk management policies and reviews volume limitations, types of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The
master contracts with the approved counterparties identify the President and Chief Financial Officer as the only representatives authorized to execute trades. The Board of Directors also reviews the status and results of derivative activities quarterly.
Income Taxes
Under Statement of Financial Accounting Standards No. 109 (“SFAS No. 109”), “Accounting for Income Taxes,” deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We routinely assess the realizability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.
Contingencies
Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.
Volatility of Oil and Natural Gas Prices
Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.
We periodically review the carrying value of our oil and natural gas properties under the full cost method of accounting rules. See “—Critical Accounting Policies—Oil and Natural Gas Properties.”
To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps, costless collars and, occasionally, put options, in order to establish some price floor protection.
The following table includes oil and natural gas positions settled during the three and nine-months period ended September 30, 2007 and 2006, and the unrealized gain/(loss) associated with the outstanding oil and natural gas derivatives at September 30, 2007 and 2006.
| | | Three months ended | | | Nine months ended | |
| | | September 30, | | | September 30, | |
| | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| Oil positions settled (Bbls) | | | 18,300 | | | | 27,600 | | | | 18,300 | | | | 63,800 | |
| Natural gas positions settled (MMBtu) | | | 1,898,000 | | | | 1,163,000 | | | | 5,332,000 | | | | 3,520,000 | |
Realized gain ($ millions) (1) | | $ | 2.8 | | | $ | 1.1 | | | $ | 5.4 | | | $ | 3.6 | |
Unrealized gain/(loss) ($ millions) (1) | | $ | 1.0 | | | $ | 2.9 | | | $ | (3.5 | ) | | $ | 7.5 | |
| | | | | | | | | | | | | | | | | |
__________
(1) Included in gain (loss) on derivatives, net in the Consolidated Statements of Income.
At September 30, 2007, we had the following outstanding natural gas derivative positions:
| | | Natural Gas | | | Natural Gas | |
| | | Swaps | | | Collars | |
| | | | | | Average | | | | | | Average | | | Average | |
Quarter | | MMbtu | | | Fixed Price(1) | | | MMBtu | | | Floor Price(1) | | | Ceiling Price(1) | |
| Fourth Quarter 2007 | | | 828,000 | | | $ | 7.44 | | | | 644,000 | | | $ | 7.24 | | | $ | 8.84 | |
| First Quarter 2008 | | | 273,000 | | | | 7.94 | | | | 1,456,000 | | | | 7.49 | | | | 9.26 | |
| Second Quarter 2008 | | | 273,000 | | | | 7.94 | | | | 1,092,000 | | | | 7.23 | | | | 8.97 | |
| Third Quarter 2008 | | | 276,000 | | | | 7.94 | | | | 920,000 | | | | 7.22 | | | | 8.97 | |
| Fourth Quarter 2008 | | | 276,000 | | | | 7.94 | | | | 1,103,000 | | | | 7.18 | | | | 8.83 | |
| First Quarter 2009 | | | - | | | | - | | | | 1,080,000 | | | | 7.09 | | | | 8.81 | |
| Second Quarter 2009 | | | - | | | | - | | | | 1,092,000 | | | | 7.09 | | | | 8.81 | |
| Third Quarter 2009 | | | - | | | | - | | | | 1,104,000 | | | | 7.09 | | | | 8.81 | |
| Fourth Quarter 2009 | | | - | | | | - | | | | 1,104,000 | | | | 7.09 | | | | 8.81 | |
| | | | | | | | | | | | | | | | | | | | | |
In addition to the information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.
The following table presents information regarding the Company’s purchases of its common stock on a monthly basis during the third quarter of 2007:
